Methods For Establishing A Subsurface Fracture Network

ABSTRACT

A method of creating a network of fractures in a reservoir is provided. The method includes designing a desired fracture network system, and determining required in situ stresses to create the desired fracture network within the reservoir. The method further includes designing a layout of wells to alter the in situ stresses within the stress field, and then injecting a fracturing fluid under pressure into the reservoir to create an initial set of fractures within the reservoir. The method also includes monitoring the in situ stresses within the stress field, and modifying the in situ stresses within the stress field. The method then includes injecting a fracturing fluid under pressure into the reservoir in order to expand upon the initial set of fractures and to create the network of fractures. A method for producing hydrocarbons from a subsurface formation is also provided herein, wherein a fracture network is created from a single, deviated wellbore production.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the priority benefit of U.S. Provisional Patent Application 61/405,069 filed 20 Oct. 2010 entitled METHODS FOR ESTABLISHING A SUBSURFACE FRACTURE NETWORK, the entirety of which is incorporated by reference herein.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

FIELD

The present inventions relate to the formation of artificial fractures in a subsurface formation. More specifically, the inventions relate to the manipulation of in situ stresses within a subsurface formation in order to control the propagation of fractures from wells completed in the formation.

GENERAL DISCUSSION OF TECHNOLOGY

Natural resources sometimes reside in subsurface formations in the form of a fluid. Such natural resources include oil, gas, coal bed methane, and geothermal steam. Typically, such natural resources reside many feet below the surface.

In order to access hydrocarbon fluids or steam, one or more wellbores is formed from the surface down to the depth of the subsurface formation. The wellbore provides fluid communication between the surface and the subsurface formation. Fluids may then be transported to the surface, either by means of reservoir pressure, by means of artificial pressure, through pumping, or by combinations thereof.

The recovery of such natural resources is sometimes made difficult by the nature of the rock matrix in which they reside. In this respect, some rock matrices have very limited permeability. Examples of formations where the rock matrix has low permeability are the shale gas reservoirs found in North America. These include the Marcellus shale formation, the Barnett shale formation, the Haynesville shale formation, and the Horn River shale formation. Another example of a formation where the rock matrix has low permeability is the so-called tight gas sandstone and siltstone intervals found in the Piceance Basin.

It is well known in the oil and gas industry to increase permeability in a subsurface rock matrix through hydraulic fracturing. Hydraulic fracturing is a technique involving the injection of fluid under high pressure into a selected subsurface zone. The fluid is pumped into the wellbore, and then injected through perforations previously shot in production casing and into the surrounding rock matrix. Typically, the rock matrix is a hydrocarbon bearing formation. The fluid is injected at a pressure sufficient enough to create fractures within the rock matrix extending from the perforations. This pressure is sometimes referred to as a “parting” pressure or a “fracturing” pressure. Preferably, the fluid includes a proppant used to hold the fractures open after the fluid pressure is relieved.

A problem encountered with hydraulic fracturing is that the fractures do not always propagate from the wellbore in a direction that is optimal for well productivity or injection. Further, fractures may propagate from different zones in parallel orientations. This means that the fractures do not interconnect, and the artificial fluid channels created for fluid flow to the wellbore remain somewhat isolated.

The orientation of fractures in an underground formation is generally controlled by the in situ stress of the formation. It is known that subsurface formations are subjected to three principal stresses. These represent a vertical stress and two orthogonal horizontal stresses. When a formation is hydraulically fractured, the created fractures should propagate along a path of least resistance. Under principals of geomechanics, the path of least resistance should be in a direction that is perpendicular to the direction of least principal stress.

In deeper formations (generally, formations deeper than about 1,000 to 2,000 feet), one of the horizontal stresses is usually the smallest stress. Consequently, fractures tend to propagate vertically and/or horizontally perpendicular to the direction of least principal stress, the fractures together forming an approximately vertically oriented planar fracture. In other words, if the horizontal directions are the x and y axes and the vertical direction is defined by a z axis, and the direction of least principal stress is in the x direction, fractures would form in the y-z plane. This is also generally true for any naturally occurring fractures which may be present in the deeper formation.

Attempts have been made in the past to modify the direction in which fractures propagate. For example, in U.S. Pat. No. 5,111,881, entitled “Method to Control Fracture Orientation in Underground Formation,” it was proposed to first determine the anticipated fracture orientation of a hydrocarbon-bearing formation. The wellbore was then perforated in the anticipated direction of the fracture, and fluid was injected into the wellbore to form a first fracture. A substance was then injected into the first fracture which would temporarily harden. The formation was then perforated in a direction perpendicular to the original anticipated fracture orientation of the hydrocarbon bearing formation, and re-fractured to form a second fracture. It was believed that the second fracture would propagate in a direction away from that of the first fracture. The result was that independent fractures in two horizontal directions would be formed.

The '881 patent also suggested a modified arrangement to this process. The operator would first determine whether the stress field around a first hydraulic fracture would be altered to allow a reversal of the in situ stresses. The anticipated initial fracture orientation of the hydrocarbon-bearing formation is then determined. The formation is then perforated in a direction parallel to the anticipated fracture orientation, and also perforated in a direction perpendicular to the anticipated fracture orientation. The formation is then fractured in each of the two directions simultaneously.

U.S. Pat. Publ. No. 2009/0095482 and U.S. Pat. Publ. No. 2009/0194273 describe a method for orchestrating multiple subsurface fractures at multiple well locations in a region. This is done by flowing a well treatment fluid from a centralized well treatment fluid center. In operation, a fracture is formed at a first well location, and the effects of that fracture on stress fields within the formation are measured. Sensors disposed about the region are adapted to output effects on the stress fields. This process is then repeated for subsequent fractures. The location and orientation of subsequent fractures are based on the combined stress effects on the stress fields as a result of the prior fractures.

The above publications also disclose a method of servicing multiple well locations. The method includes the step of configuring a central location for the distribution of “well development task fluids to centralized service factories” through fluid lines. The method also includes preparing the treatment fluids at the centralized service factories, and treating wells with the treatment fluids according to well development tasks associated with each well.

As can be seen, the methods of the above publications focus on coordinating the flow of fluids from a centralized well treatment fluid center. The methods ostensibly provide for “optimal region development.”

U.S. Pat. No. 4,830,106 entitled “Simultaneous Hydraulic Fracturing,” describes the use of simultaneous fracturing to change fracture trajectories due to the pressurization of the formation. Fracturing is conducted in at least two wellbores simultaneously, causing the fractures to propagate in a direction contrary to the far-field in situ stresses. The fractures may curve away from each well or towards each well depending on the relative position and spacing of the wells in the stress field and the magnitude of the applied far field stresses. Preferably, the generated fractures will intercept at least one naturally-occurring fracture in the hydrocarbon-bearing interval.

U.S. Pat. No. 4,724,905, also entitled “Simultaneous Hydraulic Fracturing,” discloses the use of hydraulic fracturing in one well to control the direction of propagation of a second hydraulic fracture in a second well located nearby. The first well is fractured, with the fractures generally forming parallel to the fractures in the natural fracture system. The hydraulic pressure is maintained in the first well, and another hydraulic fracturing operation is conducted at the second well within a zone of anticipated in situ stress alteration caused by the first hydraulic fracture. Preferably, the second hydraulic fracture propagates at an angle that is substantially perpendicular to the first hydraulic fracture.

A need exists for an improved method of creating a network of fractures. More specifically, a need exists for a method of creating a fracture network wherein a desired fracture network system is determined for a group of wells or even for a field before all of the wells are completed. Further, a need exists for a method of producing hydrocarbons from a single deviated wellbore by manipulating in situ stresses through sequential producing and fracturing stages in the single wellbore.

SUMMARY

A method of creating a network of fractures in a reservoir is first provided. The reservoir has an in situ stress field. The method has particular application to subsurface rock formations having a permeability that is less than 10 millidarcies.

In one embodiment, the method includes designing a desired fracture network system. The fracture network system represents a system of fractures or, alternatively, sets of fractures. The fractures are designed to interconnect within the reservoir. The step of designing a desired fracture network is done using geomechanical simulation, which involves use of a software program and a processor.

The method also includes determining required in situ stresses to create the desired fracture network within the reservoir. Determining required in situ stresses may be done by, for example, (i) reviewing downhole pressure measurements from existing wells, (ii) reviewing micro-seismic and/or tiltmeter monitoring conducted in existing wells, (iii) conducting downhole stress modeling, or (iv) combinations thereof.

The method further includes designing a layout of wells to alter the in situ stresses within the stress field. The layout may refer to the location of wellheads at the surface, the orientation of wellbores along the reservoir, the completion architecture, or combinations thereof.

The method additionally includes injecting a fracturing fluid under pressure into the reservoir. The purpose is to create an initial set of fractures within the reservoir. The fluid may be injected through wells completed for the production of hydrocarbon fluids. Alternatively or in addition, the fluid may be injected through wells completed for the injection of fluids, such as brine.

The method also includes monitoring the in situ stresses within the stress field. Monitoring may be done by, for example, (i) reviewing downhole pressure measurements from wells in the field, (ii) reviewing micro-seismic and/or tiltmeter monitoring conducted in wells in the field, (iii) conducting downhole stress modeling, or (iv) combinations thereof.

The method additionally includes updating the geomechanical simulation based on the monitored in situ stresses. Further, the method includes designing a program of modifying the in situ stress within the stress field. The step of designing a program is also done using geomechanical simulation.

The method further includes modifying the in situ stresses within the stress field. In one aspect, the modifying step is performed at least in part by producing hydrocarbon fluids from the reservoir. In another aspect, the modifying step is performed at least in part by injecting fluids into the reservoir. This injection is for the purpose of increasing pore pressure, and not to further fracture the reservoir. The injection of fluids may take place through a plurality of wells either simultaneously, or in stages such that fluid is injected into two or more wells sequentially.

Modifying the in situ stresses may further comprise (i) specifying a length of time for injecting for selected wells, (ii) specifying a viscosity of fluid for injection into selected wells, (iii) modifying a temperature of the reservoir, or (iv) combinations thereof. Alternatively, modifying the in situ stresses may comprise providing new perforations into the reservoir from selected wellbores, with the perforations being shot at a non-transverse angle relative to the wellbores.

The method then includes injecting a fracturing fluid under pressure into the reservoir in order to expand upon the initial set of fractures and to create the desired fracture network. Preferably, injecting a fluid under pressure into the reservoir comprises injecting a fluid through a plurality of wells that are part of the layout of wells.

In one aspect of the method, at least two wells in the layout of wells are completed for the production of hydrocarbon fluids. In this instance, the network of fractures is designed to optimize production of the hydrocarbon fluids. Optionally, injecting a fracturing fluid under pressure into the reservoir comprises injecting the fluid through the at least two wells completed for the production of hydrocarbon fluids. The method then further comprises producing hydrocarbon fluids from the wells completed for the production of hydrocarbon fluids after the initial set of fractures is created.

In another aspect, at least two wells in the layout of wells are completed for the injection of fluids as part of enhanced hydrocarbon recovery. The fluids may represent an aqueous fluid such as brine. In this instance, injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of fluids.

In yet another aspect, at least two wells in the layout of wells are completed for the production of geothermally-produced steam. In this instance, the network of fractures is designed to optimize heat transfer for geothermal applications. Injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the production of the geothermally-produced steam.

In still another aspect, at least two wells in the layout of wells are completed for the injection of acid gases. In this instance, injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of acid gases. The acid gases may comprise, for example, primarily carbon dioxide. The carbon dioxide may be injected as part of an enhanced hydrocarbon recovery project. Alternatively, the carbon dioxide may be injected as part of a sequestration operation. There, the network of fractures is designed to optimize CO₂ storage capacity.

In yet another aspect, at least two wells in the layout of wells are completed for the injection of drill cuttings. In this instance, injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of drill cuttings.

A method of producing hydrocarbons from a subsurface formation is also provided herein. The formation has a permeability less than about 10 millidarcies.

In one embodiment, the method includes providing a wellbore in the subsurface formation. The wellbore has been formed as a deviated wellbore. Further, the wellbore has been perforated within the subsurface formation along at least a first zone and a second zone.

The method also includes fracturing the subsurface formation along the first and second zones. This forms a plurality of fractures extending from the wellbore in an approximately vertically oriented plane that is substantially perpendicular to the direction of least principal or minimum stress. Preferably the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation. In this instance, the fractures extend substantially transverse to the wellbore in an approximately vertically oriented plane, sometimes referred to herein as vertical fractures, that is substantially perpendicular to the direction of least principal or minimum stress.

The method then includes producing hydrocarbon fluids through the vertical fractures along the first and second zones.

The method further includes monitoring the wellbore. The wellbore is monitored to determine when a change in orientation of the maximum principal stress occurs within the subsurface formation along the first and second zones. Monitoring the wellbore may comprise (i) determining when a designated volume of hydrocarbon fluids have been produced from the wellbore; (ii) determining when a designated reduction in reservoir pressure within the subsurface formation has taken place; (iii) determining when a selected period of time of production has taken place; (iv) determining whether micro-seismic and/or tiltmeter readings indicate a change in in situ stresses; (v) or combinations thereof.

The method also includes injecting a fracturing fluid into the subsurface formation. The fluid is injected through perforations in the first and second zones. This creates a first set of new fractures within the subsurface formation that at least partially extends from the vertical fractures along a plane that is substantially transverse to, or at least angled away from, the vertical fractures. The new fractures are still located within an approximately vertically oriented plane, but the plane of the new fractures is at an angle to the vertically oriented planar network of the originally created fractures. The method further includes producing hydrocarbons through the first set of new fractures and through the vertical fractures along the first and second zones.

Preferably, the wellbore has further been perforated within the subsurface formation along a third zone. In this instance,

-   -   fracturing the subsurface formation further comprises fracturing         the subsurface formation along the third zone to form additional         vertical fractures extending from the wellbore;     -   producing hydrocarbon fluids through the vertical fractures         further comprises producing hydrocarbon fluids along the third         zone;     -   monitoring the wellbore further comprises monitoring the         wellbore to determine when a change in maximum principal stress         may occur within the subsurface formation along the third zone;     -   injecting a fracturing fluid into the subsurface formation to         create the first set of new fractures further comprises         injecting a fracturing fluid through perforations in the third         zone; and     -   producing hydrocarbons through the first set of new fractures         further comprises producing hydrocarbons through the vertical         fractures along the third zone.

In one aspect, the method further comprises injecting a fracturing fluid into the subsurface formation through perforations in the first, second, and (optional) third zones. This creates a second set of new fractures within the subsurface formation that at least partially extend from the (i) vertical fractures, (ii) the first set of new fractures, or (iii) both. The fractures in the second new set of fractures extend along a plane that may be substantially transverse to, or at least at an angle to, the vertical fractures. The method then further includes producing hydrocarbons through (i) the second set of new fractures, (ii) the first set of new fractures, and (iii) the vertical fractures along the first, second, and (optional) third zones.

The perforations along the first zone, the second zone, and the third zone are separated. For example, separation may be by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters). In addition, the vertical fractures may extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.

In a related aspect, the method further comprises:

-   -   perforating the wellbore to create new perforations along a         selected zone, with the new perforations being shot at a         non-transverse angle relative to the wellbore;     -   injecting a fracturing fluid into the subsurface formation         through the new perforations in the selected zone in order to         fracture the subsurface formation along the selected zone; and     -   producing hydrocarbon fluids through perforations along the         selected zone.

Other aspects of methods of producing hydrocarbons from a subsurface formation are also provided herein. Once again, the formation has a permeability less than about 10 millidarcies.

In some implementations, the method includes providing a wellbore in the subsurface formation. The wellbore has been completed as a deviated wellbore. Further, the wellbore has been perforated within the subsurface formation along at least a first zone and a second zone.

The method also includes fracturing the subsurface formation along the first and second zones. This forms a plurality of fractures formed in a vertical plane, referred to herein as vertical fractures, extending from the wellbore. Preferably the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation. In this instance, the vertical fractures extend substantially transverse to the wellbore.

The method then includes producing hydrocarbon fluids through the vertical fractures along the first and second zones.

The method also includes injecting a fluid into the subsurface formation. The fluid is injected through perforations in the second zone. This serves to raise the reservoir pressure in the subsurface formation along the first zone, and also causes a change in the in situ stresses within the subsurface formation along the first zone. It is noted that the fluid is not injected at a pressure in excess of the formation parting pressure.

The method further includes injecting a fluid into the subsurface formation through perforations in the first zone. In this instance, fluid injection causes a propagation of fractures in the subsurface formation along the first zone at least partially towards the second zone.

The method also includes producing hydrocarbons through the perforations along the first zone. The method may further include producing hydrocarbons through the perforations along the second zone along with the production of hydrocarbons from the first zone.

In one aspect, the method further comprises monitoring the wellbore to determine when a change in maximum principal stress may occur within the subsurface formation along the first zone as a result of injecting the fluid into the second zone. Monitoring the wellbore may be done by (i) determining when a designated volume of hydrocarbon fluids have been produced from the first zone; (ii) determining when a designated reduction in reservoir pressure within the subsurface formation along the first zone has taken place; (iii) determining when a selected period of time of production has taken place; (iv) determining whether micro-seismic and/or tiltmeter readings indicate a change in in situ stresses; (v) determining when a selected volume of fluid has been injected into the subsurface formations through the perforations in the second zone; or (vi) combinations thereof.

Preferably, the wellbore has further been perforated within the subsurface formation along a third zone. In this instance,

-   -   fracturing the subsurface formation further comprises fracturing         the subsurface formation along the third zone to form additional         vertical fractures extending from the wellbore;     -   producing hydrocarbon fluids through the vertical fractures         further comprises producing hydrocarbon fluids along the third         zone; and     -   injecting a fluid into the subsurface formation through         perforations in the second zone further raises reservoir         pressure in the subsurface formation along the third zone, and         further causes a change in the in situ stresses within the         subsurface formation along the third zone.

The method then further comprises:

-   -   injecting a fluid into the subsurface formation through         perforations in the third zone, thereby causing a propagation of         new fractures in the subsurface formation along the third zone         at least partially towards the second zone; and     -   producing hydrocarbons through the new fractures and the new         perforations along the third zone.

The method may also include producing hydrocarbons through the perforations along the first and second zones along with the production of hydrocarbons from the third zone.

The perforations along the first zone, the second zone, and the optional third zone are separated. For example, separation may be by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters). In addition, the fractures may extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.

In some implementations, the method further comprises:

-   -   discontinuing production of hydrocarbons from the first zone;     -   injecting a fluid into the subsurface formation through         perforations in the first zone, thereby raising reservoir         pressure in the subsurface formation along the second zone and         causing a change in the in situ stresses within the subsurface         formation along the second zone;     -   injecting a fluid into the subsurface formation through         perforations in the second zone, thereby causing a propagation         of new fractures in the subsurface formation along the second         zone at least partially towards the first zone; and     -   producing hydrocarbons through the new fractures and the         perforations along the second zone.

In some implementations, the method further comprises:

-   -   discontinuing production of hydrocarbons from the third zone;     -   injecting a fluid into the subsurface formation through         perforations in the third zone, thereby raising reservoir         pressure in the subsurface formation along the first zone and         causing a change in the in situ stresses within the subsurface         formation along the first zone;     -   injecting a fluid into the subsurface formation through         perforations in the second zone, thereby causing a propagation         of new fractures in the subsurface formation along the second         zone at least partially towards the third zone; and     -   producing hydrocarbons through the new fractures and the         perforations along the second zone.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certain drawings, charts, graphs and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 is a cross-sectional view of an illustrative wellbore. The wellbore has been completed as a deviated wellbore within a subsurface formation. The subsurface formation contains hydrocarbon fluids.

FIGS. 2A through 2K are perspective views of a bottom portion of the wellbore of FIG. 1. The wellbore is divided or apportioned into three illustrative zones for the production of hydrocarbon fluids from the subsurface formation. The wellbore is lined with a string of production casing.

In FIG. 2A, the casing has been perforated in each of a first zone, a second zone, and a third zone.

In FIG. 2B, a fracturing fluid is being injected through the perforations in the casing. The subsurface formation is being fractured along the first zone, the second, and the third zone.

In FIG. 2C, vertical fractures have been formed in each of the first, second, and third zones.

In FIG. 2D, the wellbore has been placed in full production. Hydrocarbon fluids are being produced from the subsurface formation along each of the first, second, and third zones. A first zone of production is seen along each of the wellbore zones.

In FIG. 2E, production from the wellbore has been temporarily suspended. Fluid is now being injected through the perforations along each of the first, second, and third zones under high pressure.

In FIG. 2F, a first new set of fractures is formed in each of the first, second and third zones. The new sets of fractures extend from the original vertical fractures at least partially in a direction that is transverse to the original vertical fractures.

In FIG. 2G, the wellbore has been placed back in production. Hydrocarbon fluids are again being produced from the subsurface formation along each of the first, second, and third zones. A second larger zone of production is seen along each of the zones.

In FIG. 2H, production from the wellbore has been temporarily suspended. Fluid is now being reinjected under high pressure into the subsurface formation through perforations in each of the first, second, and third zones.

In FIG. 2I, a second new set of fractures has been formed. The fractures in the second new set of fractures extend from the original vertical fractures and the first new set of fractures.

In FIG. 2J, the wellbore has been put back into production. Hydrocarbon fluids are being produced through the second and first new sets of fractures, along with the original vertical fractures. A third larger zone of production is seen around each of the zones.

In FIG. 2K, new intermediate perforations have been formed along the casing. The illustrative perforations are oriented at an angle non-transverse to the casing. The subsurface formation has also been fractured from the intermediate perforations.

FIGS. 3A and 3B are a single flowchart showing steps for performing a method of producing hydrocarbons from a subsurface formation.

FIGS. 4A through 4Q are perspective views of a bottom portion of the wellbore of FIG. 1. The wellbore is again divided into three illustrative zones for the production of hydrocarbon fluids from the subsurface formation. The wellbore is lined with a string of production casing.

In FIG. 4A, the casing has been perforated in each of a first zone, a second zone, and a third zone.

In FIG. 4B, a fracturing fluid is being injected through the perforations in the casing. The subsurface formation is being fractured along the first, the second, and the third zones.

In FIG. 4C, fractures in a vertical plane have been formed in each of the first, second, and third zones.

In FIG. 4D, the wellbore has been placed in production. Hydrocarbon fluids are being produced from the subsurface formation along each of the first, second, and third zones. A first zone of production is seen along each of the wellbore zones.

In FIG. 4E, production from the second zone has been temporarily suspended. A fluid is also being injected into the second zone. This raises the reservoir pressure along the second zone, and extending into stress fields along the first and third zones.

In FIG. 4F, production from each of the first and third zones has been temporarily suspended. Fracturing fluids are now being injected into the subsurface formation along the first and third zones under high pressure. Fluids are also being injected into the second zone to maintain formation pressure.

In FIG. 4G, first new sets of fractures have been created in the first and third zones. The first new fractures propagate at least partially towards the second (intermediate) zone. Stated another way, the new sets of fractures extend at least partially from the original vertical fractures in a direction that is at least partially transverse to the vertical fractures.

In FIG. 4H, the wellbore has been placed back in full production. Hydrocarbon fluids are again being produced from the subsurface formation along each of the first, second, and third zones. A second larger zone of production is seen along the first and third zones.

In FIG. 4I, production has been temporarily suspended from the first zone. Fluid is now being injected into the subsurface formation through perforations in the first zone to raise reservoir pressure in the first zone and extending into the stress field of the second zone.

In FIG. 4J, production has been suspended from the second zone as well. Fracturing fluid is being injected into the subsurface formation along the second zone under high pressure in order to form a new set of fractures.

In FIG. 4K, new fractures have been formed along the second zone. The fractures in the second new set of fractures extend from the original vertical fractures and towards the first zone. Stated another way, the second set of fractures extends from the original vertical fractures in a direction that is transverse, or at least partially transverse, to the vertical fractures.

In FIG. 4L, the wellbore has been put back into production. Hydrocarbon fluids are being produced through the first new sets of fractures and the original vertical fractures in each of the first, second, and third zones. A second larger zone of production is now seen along the second zone.

In FIG. 4M, production has been temporarily suspended from the third zone. Fluid is now being injected into the subsurface formation through perforations in the third zone to raise reservoir pressure in the third zone and extending into the second zone.

In FIG. 4N, production has been temporarily suspended from the second zone as well. Fluid is being injected into the subsurface formation along the second zone under high pressure in order to form a new set of fractures.

In FIG. 4O, new fractures have again been formed along the second zone. The fractures in the new set of fractures extend from the original vertical fractures and towards the third zone.

In FIG. 4P, the wellbore has been put back into production. Hydrocarbon fluids are being produced through the new sets of fractures and the original vertical fractures in each of the first, second, and third zones. A third larger zone of production is seen along the second zone.

In FIG. 4Q, new intermediate perforations have been formed along the casing. The illustrative perforations are oriented at an angle non-transverse to the casing. The subsurface formation has also been fractured from the intermediate perforations.

FIGS. 5A through 5C are a single flowchart showing steps for performing a method of producing hydrocarbons from a subsurface formation.

FIG. 6A shows a perspective view of a designed fracture network.

FIG. 6B is another perspective view of a designed fracture network

FIG. 7 provides a plan view of a hydrocarbon development area. A well layout and completion arrangement is set out for the creation of a fracture network and the subsequent production of hydrocarbon fluids.

FIG. 8 is a flow chart showing steps for performing a method of creating a network of fractures in a reservoir, in one embodiment. The reservoir preferably represents a rock matrix having a low permeability.

FIG. 9 is a flow chart setting forth various steps for determining or for monitoring in situ stresses in a stress field.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring, hydrocarbons including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the terms “produced fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, oil, pyrolyzed shale oil, gas, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).

As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, combinations of liquids and solids, and combinations of gases, liquids, and solids.

As used herein, the term “gas” refers to a fluid that is in its vapor phase at 1 atm and 15° C.

As used herein, the term “oil” refers to a hydrocarbon fluid containing primarily a mixture of condensable hydrocarbons.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

The term “zone of interest” refers to a portion of a formation containing hydrocarbons.

As used herein, the term “formation” refers to any definable subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation.

As used herein, the term “hydrocarbon-rich formation” refers to any formation that contains more than trace amounts of hydrocarbons. For example, a hydrocarbon-rich formation may include portions that contain hydrocarbons at a level of greater than 5 percent by volume. The hydrocarbons located in a hydrocarbon-rich formation may include, for example, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.

As used herein, the term “organic-rich rock” refers to any rock matrix holding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but are not limited to, sedimentary rocks, shales, siltstones, sands, silicilytes, carbonates, and diatomites. Organic-rich rock may contain kerogen.

As used herein, the term “hydraulic fracture” refers to a fracture at least partially propagated into a formation, wherein the fracture is created through injection of pressurized fluids into the formation. While the term “hydraulic fracture” is used, the inventions herein are not limited to use in hydraulic fractures. The invention is suitable for use in any fracture created in any manner considered to be suitable by one skilled in the art. The fracture may be artificially held open by injection of a proppant material. Hydraulic fractures may be substantially horizontal in orientation, substantially vertical in orientation, or oriented along any other plane.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes. As used herein, the term “well”, when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

Description of Selected Specific Embodiments

The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.

FIG. 1 is a cross-sectional view of an illustrative wellbore 100. The wellbore 100 defines a bore 105 that extends from a surface 101, and into the earth's subsurface 110. The bore 105 preferably includes a shut-in valve 108. The shut-in valve 108 controls the flow of production fluids from the wellbore 100 in the event of a catastrophic event at the surface 101.

The wellbore 100 includes a wellhead, shown schematically at 120. The wellhead 120 contains various items of flow control equipment such as a lower master fracturing valve 122 and an upper master fracturing valve 124. It is understood that the wellhead 120 will include other components during the formation and completion of the wellbore 100, such as a blowout preventer (not shown). In a subsea context, the wellhead may also include a lower marine riser package.

The wellbore 100 has been completed by setting a series of pipes into the subsurface 110. These pipes include a first string of casing 130, sometimes known as surface casing or a conductor. These pipes also include a final string of casing 150, known as a production casing. The pipes also include one or more sets of intermediate casing 140. Typically, the string of surface casing 130 and the intermediate string of casing 140 are set in place using a cement sheath. A cement sheath 135 is seen isolating the subsurface 110 along the surface casing 130, while a cement sheath 145 is seen isolating the subsurface 110 along the intermediate casing 140.

The illustrative wellbore 100 is completed horizontally. A horizontal portion is shown at 160. The horizontal portion 160 has a heel 162. The horizontal portion 160 also has a toe 164 that extends through a hydrocarbon-bearing interval 170. While the wellbore 100 is shown as a horizontal completion, it is understood that the present inventions have equal application in deviated wells that extend through more than one zone of interest.

In FIG. 1, the horizontal portion 160 of the wellbore 100 extends laterally through a formation 170. The formation 170 may be a carbonate or sand formation having good consolidation but poor permeability. More preferably, however, the formation 170 is a shale formation having low permeability. In any instance, the formation 170 may have a permeability of less than 100 millidarcies, or less than 50 millidarcies, or less than 10 millidarcies, or even less than 1 millidarcy.

For the illustrative wellbore 100, the production casing 150 represents a liner. This means that the casing 150 does not extend back to the surface 101, but is hung from an intermediate string of casing 140 using a liner hanger 152. The production casing 150 extends substantially to the toe 164 of the wellbore 100, and is cemented in place with a cement sheath 155.

The horizontal portion 160 of the wellbore 100 extends for many hundreds of feet. For example, the horizontal portion 160 may extend for over 250 feet, or over 1,000 feet, or even more than 5,000 feet. Extending the horizontal portion 160 of the wellbore 100 such great distances increases the exposure of the low-permeability formation 170 to the wellbore 100.

To permit the in-flow of hydrocarbon fluids from the formation 170 into the production casing 150, the production casing 150 is perforated. Perforations are shown at 157. While only three sets of perforations 157 are shown, it is understood that the horizontal portion 160 may have many more sets of perforations 157.

In preparation for the production of hydrocarbons, the operator may wish to stimulate the formation 170 by circulating an acid solution. This serves to clean out residual drilling mud both along the wall of the borehole 105 and into the near-wellbore region (the region within formation 170 close to the production casing 150). In addition, the operator may wish to fracture the formation 170. This is done by injecting a fracturing fluid under high pressure through the perforations 157 and into the formation 170. The fracturing process creates fissures 159 along the formation 170 to enhance fluid flow into the production casing 150.

To facilitate the injection of fracturing fluid and stimulation fluid into the formation 170, the wellbore 100 may be apportioned into sections or zones. In the illustrative wellbore 100 of FIG. 1, the horizontal portion 160 is divided into three zones 154, 156, 158. While only three zones are shown in FIG. 1, it is understood that a horizontally completed wellbore may be divided into numerous additional zones. Each zone may represent, for example, a length of up to about 30 meters (100 feet). In operation, the operator may fracture and treat each zone 154, 156, 158 separately.

It is desirable to increase the complexity of fractures 159 in the formation 170. This increases the exposure of the rock matrix making up the formation 170 to the perforations 157 and, hence, to the bore 105. Therefore, a process is provided herein whereby fractures may be incrementally formed within the formation 170 at different axes and angles. Illustrative steps for such a process, in one embodiment, are shown in FIGS. 2A through 2K.

FIGS. 2A through 2K are perspective views of a bottom portion of a wellbore 200. The wellbore 200 may be the bottom portion of illustrative wellbore 100 of FIG. 1, in one embodiment. The wellbore 200 is completed as a deviated wellbore through a subsurface formation 250. The illustrative wellbore 200 is completed substantially horizontally.

The subsurface formation 250 represents a rock matrix having limited permeability. For example, the formation may have a permeability less than about 10 millidarcies. The subsurface formation represents a hydrocarbon-producing reservoir such as a tight-gas formation, a shale gas formation, or a coal bed methane formation. The reservoir may contain methane along with so-called acid gases such as carbon dioxide and hydrogen sulfide. The reservoir may also incidentally contain water or brine.

The wellbore 200 includes a string of casing 202. The casing 202 has been cemented into the formation 250. A cement sheath 204 is shown cut away in each of FIGS. 2A through 2K. The casing 202 defines an elongated tubular body forming a bore 205 therethrough. In the wellbore arrangement of FIGS. 2A through 2K, the bore 205 is bifurcated into sections 240 and 245. The sections 240, 245 are separated by a wall 242 so that no fluid communication exists between the sections 240, 245. Each of sections 240 and 245 has a semi-circular profile. However, other profiles may be employed.

The benefit of bifurcating the bore 205 is that it permits the operator to alternatively produce fluids from and inject fluids into the subsurface formation 250. This may be done without running alternating strings of production tubing and injection tubing into and out of the casing 202. However, the methods claimed below permit either the use of a bifurcated tubular body or the cyclical running of production and tubing strings. Further, the claims allow for the placement of both a tubing string and an injection string together within the bore 205 of the casing (as shown in FIGS. 4A through 4Q).

In FIG. 2A, separate arrows “P” and “I” are seen. Arrow “I” indicates a path of injection for fluids into the subsurface formation 250. Injection fluids may travel through section 240. Similarly, arrow “P” indicates a flow of production fluids from the subsurface formation 250. Production fluids may travel through section 245.

In each of FIGS. 2A through 2K, the wellbore 200 is divided into three illustrative zones 210, 220, 230. Each zone 210, 220, 230 is within the subsurface formation 250 and passes through hydrocarbon fluids.

In FIG. 2A, the casing 202 has been perforated in the first zone 210, the second zone 220, and the third zone 230. Perforations in the first zone 210 are seen at 212; perforations in the second zone 220 are seen at 222; and perforations in the third zone 230 are seen at 232. The perforations 212, 222, 232 extend through the casing 202 and the cement sheath 204, and place the bore 205 in fluid communication with the surrounding formation 250.

FIG. 2B presents a next view of the wellbore 200. In FIG. 2B, a fracturing fluid is being injected into the subsurface formation 250. Fluid flows into section 240 in accordance with arrow “I.” From there, the fluid flows under high pressure through the perforations 212, 222, 232 in the casing 202, and into the subsurface formation 250. Arrows 216 indicate the flow of fracturing fluid into the first zone 210; arrows 226 indicate the flow of fluid into the second zone 226; and arrows 236 indicate the flow of fluid into the third zone 236.

FIG. 2C presents a next view of the wellbore 200. In FIG. 2C, the fracturing fluid has created vertical fractures in each of the first 210, second 220, and third 230 zones. Vertical fractures 214′ are formed along the first zone 210; vertical fractures 224′ are formed along the second zone 220; and vertical fractures 234′ are formed along the third zone 230. While the vertical fractures 214′, 224′, 234′ are shown in linear form, it is understood that the fractures will actually be planar. In addition, while each of the vertical fractures 214′, 224′, 234′ are shown in only two lines, it is understood that each zone 210, 220, 230 will most likely be fractured along more than one vertical plane. Again, it also understood that while fractures are referred to and illustrated as vertical fractures, that fractures tend to propagate vertically and/or horizontally perpendicular to the direction of least principal stress, the fractures together forming an approximately vertically oriented planar fracture. In other words, if the horizontal directions are the x and y axes and the vertical direction is defined by a z axis, and the direction of least principal stress is in the x direction, multiple fractures would form in the y-z plane.

FIG. 2D presents a next view of the wellbore 200. In FIG. 2D, the wellbore 200 has been placed in full production. Hydrocarbon fluids are being produced from the subsurface formation 250 along each of the first 210, second 220, and third 230 zones. Fluids flow from the subsurface formation 250, through the vertical fractures 214′, 224′, 234′, and through the respective perforations 212, 222, 232. From there, production fluids flow through section 245 within the casing 202, and towards the surface (not shown) according to arrow “P.”

It is noted that each of the fractures 214′, 224′, 234′ creates a first zone of production. This is indicated schematically in FIG. 2D. The first zone of production in the first zone 210 is seen at 215′; the first zone of production in the second zone 220 is seen at 225′; and the first zone of production in the third zone is seen at 235′. Because of the low permeability of the rock matrix making up the subsurface formation 250, the zones of production 215′, 225′, 235′ remain closely tied to the fracture planes created by the vertical fractures 214′, 224′, 234′.

In accordance with one of the methods of producing hydrocarbons herein, the wellbore 200 is monitored during production. Particularly, the wellbore 200 is monitored to determine when a change in the orientation of maximum principal stress may occur within the subsurface formation 250.

The wellbore 200 may be monitored in various ways. For example, monitoring the wellbore 200 may comprise determining when a designated volume of hydrocarbon fluids have been produced from the wellbore 200. Alternatively, monitoring the wellbore 200 may comprise determining when a designated reduction in reservoir pressure within the subsurface formation 250 has taken place. This may be done through reservoir simulation or may be based on experience with existing wells in the field.

Alternatively still, monitoring the wellbore 200 may comprise determining when a selected period of time of production has taken place. And alternatively still, monitoring the wellbore 200 may comprise determining whether micro-seismic readings or tilt-meter readings indicate a change in in situ stresses. Combinations of these techniques are preferably employed.

FIG. 2E presents a next view of the wellbore 200. In FIG. 2E, production from the wellbore 200 has been suspended. This takes place once it is determined that the orientation of maximum principal stress in the first 210, second 220, and third 230 zones has changed. In FIG. 2E, fluid is now being injected through the perforations 212, 222, 232 along each of the three zones 210, 220, 230 under high pressure. Fluid travels according to injection arrow “I” into the first section 240 of the casing 202. Fluid then exits the casing 202 through the perforations 212, 222, 232 according to respective fracture injection arrows 216, 226, 236.

FIG. 2F presents a next view of the wellbore 200. In FIG. 2F, a first new set of fractures is formed in each of the first 210, second 220, and third 230 zones. New fractures in the first zone 210 are seen at 214″; new fractures in the second zone 220 are seen at 224″; and new fractures in the third zone 230 are seen at 234″. The new fractures 214″ in the first zone 210 largely extend from the original vertical fractures 214′ in that zone 210. Similarly, the new fractures 224″ in the second zone 220 largely extend from the original vertical fractures 224′ in that zone 220. Similarly still, the new fractures 234″ in the third zone 230 largely extend from the original vertical fractures 234′ in that zone 230. Each of the new fractures 214″, 224″, 234″ extends at least partially in a direction that is transverse to the respective vertical fractures 214′, 224′, 234′. This is because of the change in maximum principal stress within the subsurface formation 250. The result is that the complexity of the fracture network within the subsurface formation 250 has beneficially increased, even using just a single wellbore.

The direction in which the new fractures 214″, 224″, and 234″ propagate should be re-emphasized. Because of the change in maximum principal stress within the subsurface formation 250, the new fractures 214″, 224″, 234″ will at least initially extend away from the planes of the original vertical fractures 214′, 224′, and 234′. However, as the new fractures 214″, 224″, and 234″ propagate away from the vertical fractures 214′, 224′, 234′, they move through a transition area of maximum principal stress and begin to bend back so that the plane formed by the new fractures 214″, 224″, and 234″ is in approximate alignment or parallel with the plane formed by the original vertical fractures 214′, 224′ and 234′.

FIG. 2G presents a next view of the wellbore 200. In FIG. 2G, the wellbore 200 has been placed back in full production. Hydrocarbon fluids are again being produced from the subsurface formation 250 along each of the first 210, second 220, and third 230 zones. In the first zone 210, fluids flow from the subsurface formation 250, through the first set of new fractures 214″, through the vertical fractures 214′, through the perforations 212, and into the casing 202. In the second zone 220, fluids flow from the subsurface formation 250, through the first set of new fractures 224″, through the vertical fractures 224′, through the perforations 222, and into the casing 202. In the third zone 230, fluids flow from the subsurface formation 250, through the first set of new fractures 234″, through the vertical fractures 234′, through the perforations 232, and into the casing 202.

The fluids from the various zones 210, 220, 230 are commingled within the second section 245 of the casing 202. From there, production fluids flow toward the surface according to arrow “P.”

It is noted that in connection with each zone 210, 220, 230, the new fractures 214″, 224″, 234″ create respective second zones of production. This is indicated schematically in FIG. 2G. The second zone of production in the first zone 210 is seen at 215″; the second zone of production in the second zone 220 is seen at 225″; and the second zone of production in the third zone 230 is seen at 235″. Because of the low permeability of the rock matrix making up the subsurface formation 250, the zones of production 215″, 225″, 235″ remain closely tied to the fracture planes created by the new sets of fractures 214″, 224″, 234″. However, the second zones of production 215″, 225″, 235″ are larger than their respective first zones of production 215′, 225′, 235′.

In accordance with one of the methods of producing hydrocarbons herein, the wellbore 200 is once again monitored during production. Particularly, the wellbore 200 is monitored to determine when a change in the orientation of maximum principal stress may once again occur within the subsurface formation 250.

FIG. 2H presents a next view of the wellbore 200. In FIG. 2H, production from the wellbore 200 has been suspended. This takes place once it is determined that the orientation of maximum principal stress in the first 210, second 220, and third 230 zones has once again changed. In FIG. 2H, fluid is now being re-injected through the perforations 212, 222, 232 along each of the three zones 210, 220, 230 under high pressure. Fluid travels according to injection arrow “I” into the first section 240 of the casing 202. Fluid then exits the casing 202 through the perforations 212, 222, 232 according to respective fracture injection arrows 216, 226, 236.

FIG. 2I presents a next view of the wellbore 200. In FIG. 2I, a second new set of fractures is formed in each of the first 210, second 220, and third 230 zones. New fractures in the first zone 210 are seen at 214″′; new fractures in the second zone 220 are seen at 224″′; and new fractures in the third zone 230 are seen at 234″′. The new fractures 214″′ in the first zone 210 largely extend from the first new fractures 214″ in that zone 210. Similarly, the new fractures 224′″ in the second zone 220 largely extend from the first new fractures 224″ in that zone 220. Similarly still, the new fractures 234″′ in the third zone 230 largely extend from the first new fractures 234″ in that zone 230.

Each of the second new fractures 214″′, 224″′, 234″′ extends at least partially in a direction that is transverse to the respective vertical fractures 214′, 224′, 234′. This is because of the change in maximum principal stress within the subsurface formation 250. The result is that the complexity of the fracture network within the subsurface formation 250 has beneficially increased. However, as the second new fractures 214″′, 224″′, and 234″′ propagate away from the vertical fractures 214′, 224′, 234′, they move through a transition area of maximum principal stress and begin to bend back so that the plane formed by the new fractures 214″′, 224″′, and 234″′ is in approximate alignment or parallel with the plane formed by the original vertical fractures 214′, 224′ and 234′, just as the first new fractures 214″, 224″, 234″ did.

FIG. 2J presents a next view of the wellbore 200. In FIG. 2J, the wellbore 200 has been put back into production. Hydrocarbon fluids are again being produced from the subsurface formation 250 along each of the first 210, second 220, and third 230 zones. In the first zone 210, production fluids flow from the subsurface formation 250 and through the fracture network formed by fractures 214′, 214″, and 214″′. The production fluids then flow through the perforations 212 and into the casing 202. In the second zone 220, production fluids flow from the subsurface formation 250 and through the fracture network formed by fractures 224′, 224″, 224′″. The production fluids then flow through the perforations 222 and into the casing 202. In the third zone 230, production fluids flow from the subsurface formation 250 and through the fracture network formed by fractures 234′, 234″, 234″′. The production fluids then flow through the perforations 232 and into the casing 202.

The fluids from the various zones 210, 220, 230 are commingled within the second section 245 of the casing 202. From there, production fluids flow toward the surface according to arrow “P.”

It is noted that in connection with each zone 210, 220, 230, the new fractures 214″′, 224″′, 234″′ create respective third zones of production. This is indicated schematically in FIG. 2J. The third zone of production in the first zone 210 is seen at 215″′; the third zone of production in the second zone 220 is seen at 225″′; and the third zone of production in the third zone is seen at 235″′. Because of the low permeability of the rock matrix making up the subsurface formation 250, the zones of production 215″, 225″, 235″ remain closely tied to the fracture planes created by the second new fractures 214″, 224″, 234″. However, the third zones of production 215″′, 225″′, 235″′ are larger than their respective second zones of production 215″, 225″, 235″.

As can be seen, multiple cycles of fracturing, producing, and monitoring may be employed in order to create an ever-expanding network of fractures. However, in low-permeability formations the fracture networks created within the separate zones may or may not interconnect. Accordingly, an additional optional fracturing step may be employed. That step involves the placement of additional perforations and corresponding fractures intermediate to the first 210, second 220, and/or third 230 zones.

FIG. 2K presents this optional additional step. In FIG. 2K, new intermediate perforations have been formed along the casing 202. First, perforations 262 are formed between the first zone 210 and the second zone 220. Second, perforations 272 are formed between the second zone 220 and the third zone 230. Intermediate fractures 264 are created from perforations 262, while intermediate fractures 274 are created from perforations 274.

It is preferred that the perforations 262, 272 be oriented at an angle that is non-transverse to the casing 202. In this way, fractures 264, 274 are at least initially propagated at an angle, and may intersect with fractures in adjoining zones.

FIGS. 3A and 3B present a flow chart showing steps for a method 300 of producing hydrocarbons from a subsurface formation. The method 300 generally presents the steps from FIGS. 2A through 2K.

The method 300 has application to subsurface formations with limited permeability. The method 300 is particularly beneficial to formations having a permeability less than about 10 millidarcies. According to the method 300, the subsurface formation represents a hydrocarbon-producing reservoir such as a tight-gas formation, a shale gas formation, or a coal bed methane formation. The reservoir may contain methane along with so-called acid gases such as carbon dioxide and hydrogen sulfide.

The method 300 first includes providing a wellbore in the subsurface formation. This is shown at Box 305. The wellbore has been formed as a deviated wellbore. Preferably, the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation.

For purposes of this disclosure, the term “providing” is intended to be broad. “Providing” a wellbore means that the wellbore has been drilled by a government, by a company, or by an individual, association, or partnership. Alternatively, “providing” may mean that a drilling company or a service company has drilled the wellbore at the request or direction of a government, a company, or an individual, association or partnership. Alternatively still, “providing” may mean that a government, an individual, an association, or a business concern has purchased the wellbore. In any instance, the wellbore has been perforated within the subsurface formation along at least a first zone and a second zone. The wellbore may have been perforated by the owner, the lessor, or by a service company or business affiliate on behalf of the owner or lessor.

The method 300 also includes fracturing the subsurface formation along the first and second zones. This is provided at Box 310. Fracturing the formation along these zones creates one or more substantially vertical fractures extending from the wellbore. Where the wellbore is substantially horizontal, the fractures will be transverse to the wellbore, oriented in a vertical plane.

The method 300 further includes producing hydrocarbon fluids through the vertical fractures along the first and second zones. This is seen at Box 315. In one aspect, the vertical fractures extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore. Of course, non-hydrocarbon fluids such as water and carbon dioxide may be incidentally produced along with the hydrocarbon fluids.

The method 300 also includes monitoring the wellbore. This is provided at Box 320. Monitoring the wellbore is conducted to determine when a change in the direction or orientation of maximum principal stress may occur within the subsurface formation along the first and second zones. The wellbore may be monitored in a number of different ways as discussed above.

The method 300 additionally includes injecting a fracturing fluid into the subsurface formation. This is provided at Box 325. The fluid is preferably a hydraulic fluid such as brine. However, liquid CO₂, foamed nitrogen, or other non-reactive fluids may also be injected. The fluid is injected through perforations in the first and second zones. This serves to create first new fractures within the subsurface formation that at least partially extend from the vertical fractures along a plane that is substantially transverse to, or at least at an angle to, the vertical fractures.

The method 300 also includes producing hydrocarbons. This is shown at Box 330. Hydrocarbon fluids are produced through the first new fractures and through the vertical fractures along the first and second zones.

The method 300 as described above only recites two zones. However, the method 300 may include more than two zones. In one aspect, the wellbore is perforated to create new perforations along a third zone. This is provided at Box 335. Perforations may be provided along the first zone, the second zone, and a third zone, with the zones being separated by a distance of between, for example, about 20 feet (6.1 meters) and 500 feet (152.4 meters). The perforations along the third zone may be provided at the same time as the perforations along the first and second zones or at a later time. Accordingly, it should be understood that the methods 300 described herein may be applicable on any number of zones, including two or more zones. Additionally or alternatively, the methods 300 described herein may be implemented on multiple zones in either a simultaneous manner or in a sequential manner. For convenience in describing the methods herein, the multiple zones are referenced by ordinals such as first, second, third, etc. It should be understood that reference to a first zone in an illustration is exemplary of any of the other zones and is merely for identification purposes and for description of one zone relative to another. The principles and steps of the methods described herein may be applied with respect to any one or more zones in a wellbore.

Accordingly, in some implementations, the method 300 may then include fracturing the subsurface formation along the third zone to form additional vertical fractures extending from the wellbore. This is seen at Box 340.

Where a third zone is perforated, the method 300 also includes producing hydrocarbon fluids through the vertical fractures in the third zone. This is shown at Box 345. During production, the wellbore continues to be monitored. Hence, monitoring the wellbore further comprises monitoring the wellbore to determine when a change in orientation of maximum principal stress may occur within the subsurface formation along the third zone. This is seen at Box 350. In this embodiment, production from the third zone preferably takes place simultaneously with production from the first and second zones. In other words, the production steps in Boxes 315 and 350 may overlap.

Where a third zone is perforated, the method 300 also includes injecting a fracturing fluid through perforations in the third zone. This is provided at Box 355. The injection step of Box 355 may be done simultaneously with the injection step of Box 325. In addition, the method 300 includes producing hydrocarbons through the first set of new fractures along the third zone. This is shown at Box 360. The production step of Box 360 is preferably done simultaneously with the production step of Box 330.

It is noted here that still additional zones may optionally be perforated, fractured, and produced in accordance with the steps described above. For example, new perforations may be formed in a selected zone, as shown in Box 365 of FIG. 3B. Preferably, the new perforations along the selected zone are shot at a non-transverse angle relative to the wellbore. The subsurface formation is then fractured along the selected zone, as indicated at Box 370. Perforating the wellbore at an oriented angle helps cause fractures to form at an angle so as to intersect existing natural fractures and artificial fractures from adjoining zones.

The perforating 365 and fracturing 370 steps may be conducted in stages with the first, second, and third zones using multi-interval procedures. For the present method 300, the injection stages may be aided through the use of packers, fracturing ports, mechanical plugs, sand plugs, sliding sleeves, and other devices known in the art. Hydrocarbon fluids are then produced through the perforations along the selected zone.

It is also noted that additional cycles of fracturing, producing, and monitoring may be undertaken. Thus, the method 300 may include the step of injecting a fracturing fluid into the subsurface formation through perforations in the first, second, and third zones, thereby creating a second new set of fractures within the subsurface formation. The second new fractures will at least partially extend from the vertical fractures. Alternatively or in addition, the second new fractures will at least partially extend from the first new fractures as shown and discussed in connection with FIG. 2I. In any instance, the second new fractures extend along a plane that is at least partially transverse to the vertical fractures. Hydrocarbons are then produced through (i) the second new fractures, (ii) the first new fractures, and (iii) the vertical fractures along the first, second, and third zones.

The method 300 allows for the creation of a complex network of fractures using only a single wellbore. In the method 300, the wellbore may be divided into a plurality of zones, with the zones being fractured and produced from together. However, it is also proposed herein to create a complex network of fractures from a single wellbore wherein the various zones are not always fractured and produced from together. This is demonstrated through a process shown in FIGS. 4A through 4Q.

FIGS. 4A through 4Q provide perspective views of a bottom portion of a wellbore 400. The wellbore 400 may be the bottom portion of illustrative wellbore 100 of FIG. 1, in one embodiment. The wellbore 400 is completed as a deviated wellbore through a subsurface formation 450 having low permeability. The illustrative wellbore 400 is completed substantially horizontally.

The wellbore 400 includes a string of casing 402. The casing 402 has been cemented into the formation 450. A cement sheath 404 is seen in cut-away view in each of FIGS. 4A through 4Q. The casing 402 defines an elongated tubular body forming a bore 405 therethrough. In the wellbore arrangement of FIGS. 4A through 4Q, the bore 405 employs two separate tubing strings. These represent a first string 440 used for the injection of fluids into the subsurface formation 450, and a second string 445 used for the production of fluids from the subsurface formation 450.

The benefit of using separate strings 440, 445 within the bore 205 is that it permits the operator to alternatively inject fluids into and produce fluids from the subsurface formation 450. This may be done without running alternating strings of production tubing and injection tubing into and out of the casing 402. However, the methods claimed below also permit the use of a bifurcated tubular body or the cyclical running of production and tubing strings as discussed above.

In FIG. 4A, separate arrows “P” and “I” are seen. Arrow “I” indicates a path of injection for fluids into the subsurface formation 450. Injection fluids may travel through first tubing string 440. Similarly, arrow “P” indicates a flow of production fluids from the subsurface formation 450. Production fluids may travel through second tubing string 445.

In each of FIGS. 4A through 4Q, the wellbore 400 is divided into three illustrative zones 410, 420, 430. Each zone 410, 420, 430 is within the subsurface formation 450 and passes through hydrocarbon fluids.

In FIG. 4A, the casing 402 has been perforated in the first zone 410, in the second zone 420, and in the third zone 430. Perforations in the first zone 410 are seen at 412; perforations in the second zone 420 are seen at 422; and perforations in the third zone 430 are seen at 432. The perforations 412, 422, 432 extend through the cement sheath 404 and place the bore 405 in fluid communication with the surrounding formation 450.

FIG. 4B presents a next view of the wellbore 400. In FIG. 4B, a fracturing fluid is being injected into the subsurface formation 450. Fluid flows into tubing string 440 in accordance with arrow “I.” From there, the fluid flows under high pressure through the perforations 412, 422, 432 in the casing 402, and into the subsurface formation 450. Arrows 416 indicate the flow of fracturing fluid into the first zone 410; arrows 426 indicate the flow of fluid into the second zone 426; and arrows 436 indicate the flow of fluid into the third zone 436.

FIG. 4C presents a next view of the wellbore 400. In FIG. 4C, the fracturing fluid has created vertical fractures in each of the first 410, second 420, and third 430 zones. Vertical fractures 414′ are formed along the first zone 410; vertical fractures 424′ are formed along the second zone 420; and vertical fractures 434′ are formed along the third zone 430. While the vertical fractures 414′, 424′, 434′ are shown in linear form, it is understood that the fractures will actually be planar. In addition, while the vertical fractures 414′, 424′, 434′ are shown in only two lines, it is understood that each zone 410, 420, 430 will most likely be fractured along more than one vertical plane.

FIG. 4D presents a next view of the wellbore 400. In FIG. 4D, the wellbore 400 has been placed in full production. Hydrocarbon fluids are being produced from the subsurface formation 450 along each of the first 410, second 420, and third 430 zones. Fluids flow from the subsurface formation 450, through the vertical fractures 414′, 424′, 434′, and through the respective perforations 412, 422, 432. From there, production fluids flow through tubing string 445 within the casing 402, and towards the surface (not shown) according to arrow “P.”

It is noted that each of the fractures 414′, 424′, 434′ creates a first zone of production. This is indicated schematically in FIG. 4D as circles. The first zone of production in first zone 410 is seen at 415′; the first zone of production in the second zone 420 is seen at 425′; and the first zone of production in the third zone 430 is seen at 435′. Because of the low permeability of the rock matrix making up the subsurface formation 450, the zones of production 415′, 425′, 435′ remain closely tied to the fracture planes created by the vertical fractures 414′, 424′, 434′.

FIG. 4E presents a next view of the wellbore 400. In FIG. 4E, production from the second zone 420 has been suspended. A fluid is now being injected into the subsurface formation 450 along the second zone 420. This raises the reservoir pressure along the second zone 420, and extending into the first 410 and third 430 zones. The injection of fluids is indicated by injection arrow “I.” The fluids travel through the first tubing string 440, and exit perforations 422 in the second zone 420. The injection of fluids into the subsurface formation 450 is shown by arrows 428.

It is noted that the injection of fluids into the subsurface formation, denoted by arrows 428, is at a lower pressure than the injection of fluids for fracturing purposes. The injection of fluids under the higher fracturing pressures is denoted by arrows 426 (seen in FIG. 4B). It is preferred in the step of FIG. 4E that fluids be injected at a pressure lower than the fracturing pressure, as the purpose is to raise reservoir pressure in the subsurface formation 450 and modify in situ stresses.

At the same time as fluids are injected into the second zone 420, production continues in the first 410 and third 430 zones. The production of fluids is indicated by production arrow “P.” The simultaneous production and injection of fluids requires the use of separate flow paths. Such an approach is provided through the separate first 440 and second 445 tubing strings. Alternatively, this may be provided through separate flow-channels specially machined in a tubular body as shown at 240, 245 in FIG. 2A. Alternatively, the casing 402 may be equipped with valves or sliding sleeves along the casing 402 controlled through fiber optics or other communication means.

In one aspect, the step of FIG. 4E takes place once it is determined that the orientation of maximum principal stress in the first 410 and third 430 zones has changed. To this end, the wellbore 400 may be monitored. Particularly, the wellbore 400 may be monitored to determine when a change in the orientation of maximum principal stress may occur within the subsurface formation 450.

The wellbore 400 may be monitored in various ways. For example, monitoring the wellbore 400 may comprise determining when a designated volume of hydrocarbon fluids have been produced from the wellbore 400. Alternatively, monitoring the wellbore 400 may comprise determining when a designated reduction in reservoir pressure within the subsurface formation 450 has taken place. This may be done through reservoir simulation, or may be based on experience with existing wells in the field.

Alternatively still, monitoring the wellbore 400 may comprise determining when a selected period of time of production has taken place, or when a selected period of injection has taken place. And alternatively still, monitoring the wellbore 400 may comprise determining whether micro-seismic readings or tilt-meter readings indicate a change in in situ stresses. Combinations of these techniques are preferably employed.

In any event, at some point it is determined that in situ stresses in the subsurface formation 450 within the first zone 410 and the third zone 430 have changed. More specifically, the orientation of maximum principal stress has changed.

FIG. 4F presents a next view of the wellbore 400. In FIG. 4F, fluid is now being injected into the subsurface formation 450 along the first zone 410 and the third zone 430. Fluid travels according to injection arrow “I” into the first tubing string 440 in the casing 202. Fluid then exits the casing 402 through the perforations 412 and 432 as provided by fracture injection arrows 416 and 436, respectively.

The fluid is injected into the subsurface formation 450 under high pressure. The result is that new fractures are formed in the subsurface formation 450 along the first 410 and third 430 zones. This again is indicated by fracture injection arrows 416 and 436. At the same time, fluid is optionally also injected at a lower pressure into the subsurface formation 450 along the second zone 420. This is indicated by fluid injection arrows 428.

FIG. 4G presents a next view of the wellbore 400. In FIG. 4G, a first new set of fractures has been created in each of the first 410 and third 430 zones. The new fractures propagate at least partially towards the second (intermediate) zone 420. Stated another way, the new sets of fractures extend from the original vertical fractures in a direction that is at least partially transverse to the vertical fractures 414′, 434′.

New fractures in the first zone 410 are seen at 414″. The new fractures 414″ in the first zone 410 largely extend from the original vertical fractures 414′ in that zone 410. New fractures in the third zone 430 are seen at 434″. The new fractures 434″ in the third zone 430 largely extend from the original vertical fractures 434′ in that zone 430. Each of the new fractures 414″, 434″ extends at least partially in a direction that is transverse to the respective vertical fractures 414′, 434′. This is because of the change in maximum principal stress within the subsurface formation 450. The result is that the complexity of the fracture network within the subsurface formation 450 has beneficially increased, even by using just a single wellbore 400.

The direction in which the new fractures 414″ and 434″ propagate should be re-emphasized. Because of the change in maximum principal stress within the subsurface formation 450, the new fractures 414″, 434″ will at least initially extend away from the planes of the original vertical fractures 414′, 434′. However, as the new fractures 414″, 444″ propagate away from the vertical fractures 414′, 434′, they move through a transition area of maximum principal stress and begin to bend back in so that the plane formed by the new fractures 414″ and 444″ is in approximate alignment or parallel with the plane formed by the original vertical fractures 414′ and 434′.

FIG. 4H presents a next view of the wellbore 400. In FIG. 4H, the wellbore 400 has been placed back in full production. Hydrocarbon fluids are again being produced from the subsurface formation 450 along each of the first 410, second 420, and third 430 zones. In the first zone 410, fluids flow from the subsurface formation 450, through the first new set of fractures 414″, through the vertical fractures 414′, through the perforations 412, and into the casing 402. In the second zone 420, production fluids flow from the subsurface formation 250, through the vertical fractures 424′, through the perforations 422, and into the casing 402. In the third zone 430, production fluids flow from the subsurface formation 450, through the first new set of fractures 434″, through the vertical fractures 434′, through the perforations 432, and into the casing 402.

The fluids received from the various zones 410, 420, 430 are commingled within the second tubing string 445 of the casing 402. From there, production fluids flow toward the surface according to arrow “P.”

It is noted that in connection with each zone 410, 420, 430, the new fractures 414″ and 434″ create respective second zones of production. This is indicated schematically in FIG. 4H as circles. The second zone of production in first zone 410 is seen at 415″; the second zone of production in the third zone is seen at 435″. Because of the low permeability of the rock matrix making up the subsurface formation 450, the zones of production 415″, 435″ remain closely tied to the fracture planes created by the new sets of fractures 414″, 434″. However, the second zones of production 415″, 435″ are larger than their respective first zones of production 415′, 435′ (as shown in FIG. 4D).

The second zone 420 is also in production. However, the zone of production is still the first zone 425′. It is possible though using the current method and the singular wellbore 400 to increase the size of the zone of production along the second zone 420. This is shown in the steps provided in FIGS. 4I through 4P.

FIG. 4I presents a next view of the wellbore 400. In FIG. 4I, production has been suspended from the first zone 410. Fluid is now being injected into the subsurface formation 450 through perforations in the first zone 410 to raise reservoir pressure in the first zone 410, and extending into the second zone 420. The fluid injection is indicated by injection arrow “I” and by injection arrows 418.

The injection of fluid into the subsurface formation 450 along the first zone 410 is not for the purpose of fracturing the formation 450, but just to build reservoir pressure. In this way, the orientation of the maximum principal stress along the second zone 420 is ultimately changed.

FIG. 4J presents a next view of the wellbore 400. In FIG. 4J, production has been suspended from the second zone 420 as well. Fluid is being injected into the formation 450 under high pressure. Arrows 426 indicate a flow of fracturing fluid.

In one aspect, the step of FIG. 4J takes place once it is determined that the orientation of maximum principal stress in the second zone 420 has changed. To this end, the wellbore 400 may be monitored. Particularly, the wellbore 400 may be monitored to determine when a change in the orientation of maximum principal stress may occur within the subsurface formation 450.

At the same time as fluids are injected into the second zone 420, production continues in the third 430 zone. The production of fluids is indicated by production arrow “P.” As noted above, the simultaneous production and injection of fluids requires the use of separate flow paths. Such an approach is illustratively provided in FIG. 4I through the separate first 440 and second 445 tubing strings.

FIG. 4K presents a next view of the wellbore 400. In FIG. 4K, new fractures 424″ have been formed in the subsurface formation 450 along the second zone 420. The fractures 424″ extend from the original vertical fractures 424′ and at least partially towards the first zone 410. Stated another way, the new fractures 424″ extend from the original vertical fractures 424′ in a direction that is at least partially transverse to the vertical fractures 424′. This is because of the change in maximum principal stress within the subsurface formation 450.

FIG. 4L presents a next view of the wellbore 400. In FIG. 4L, the wellbore 400 has been put back into production. Hydrocarbon fluids are being produced from the subsurface formation 450 along each of the first 410, second 420, and third 430 zones. Fluids flow from the subsurface formation 450, through the new transverse fractures 414″, 424″, 434″, through the vertical fractures 414′, 424′, 434′, and through the respective perforations 412, 422, 432. From there, production fluids flow through tubing string 445 within the casing 402, and towards the surface according to arrow “P.”

Of note, a second zone of production 425″ is now provided along the second zone 420. This is indicated schematically as a circle in FIG. 4L. The second zone of production 425″ is larger than the first zone of production seen at 425′ in FIG. 4H.

FIG. 4M presents a next view of the wellbore 400. In FIG. 4M, production has been suspended from the third zone 430. Fluid is now being injected into the subsurface formation 450 through perforations in the third zone 430 to raise reservoir pressure in the third zone 430 and extending into the second zone 420. The fluid injection is indicated by injection arrow “I” and by injection arrows 438.

The injection of fluid into the subsurface formation 450 along the third zone 430 is not for the purpose of fracturing the formation 450, but just to build reservoir pressure. In this way, the orientation of the maximum principal stress along the second zone 420 is ultimately changed. During this time, production may continue in the second zone 420. Production fluids leave the subsurface formation through perforations 422 and according to production arrow “P.”

FIG. 4N presents a next view of the wellbore 400. In FIG. 4N, production has been suspended from the second zone 420 as well. Fluid is now being injected into the subsurface formation 450 along the second zone under high pressure in order to form yet additional fractures. The fluids travel through the first tubing string 440, and exit perforations 422 in the second zone 420. The injection of fluids into the subsurface formation 450 is shown by arrows 426.

At the same time as fluids are injected into the second zone 420, production may continue in the first zone 410. The production of fluids is indicated by production arrow “P.” As noted above, the simultaneous production and injection of fluids requires the use of separate flow paths. Such an approach is provided in FIG. 4N through the separate first 440 and second 445 tubing strings.

FIG. 4O presents a next view of the wellbore 400. In FIG. 4O, new fractures have again been formed along the second zone 420. The new fractures are seen at 424″. The new fractures 424″ extend from the original vertical fractures and towards the third zone 430.

The direction in which the new fractures 424″ propagate should be re-emphasized. Because of the change in maximum principal stress within the subsurface formation 450, the new fractures 424″ will at least initially extend away from the planes of the original vertical fractures 424′. However, as the new fractures 424″ propagate away from the vertical fractures 424′, they move through a transition area of maximum principal stress and begin to bend back so that the plane formed by the new fractures 424″ is in approximate alignment or parallel with the plane formed by the original vertical fractures 424′.

FIG. 4P presents a next view of the wellbore 400. In FIG. 4P, the wellbore 400 has been put back into full production. Hydrocarbon fluids are being produced through the new sets of fractures 414″, 424″, 434″ and the original vertical fractures 414′, 424′, 434′ in each of the first 410, second 420, and third 430 zones, respectively.

Hydrocarbon fluids are being produced from the subsurface formation 450 along each of the first 410, second 420, and third 430 zones. Fluids flow from the subsurface formation 450, through the new transverse fractures 414″, 424″, 434″, through the vertical fractures 414′, 424′, 434′, and through the respective perforations 412, 422, 432. From there, production fluids flow through tubing string 445 within the casing 402, and towards the surface according to production arrow “P.”

FIGS. 4A through 4P demonstrate steps that may be taken to increase the complexity of a fracture network in a low-permeability formation. Of importance, the steps are accomplished through a single wellbore which remains in a substantially constant state of production. As in situ stresses are changed during the course of production, additional fractures are created within the subsurface formation, creating ever-expanding zones of production. Ideally, the fractures in the various zones become interconnected.

It is noted that the steps shown in FIGS. 4A through 4P need not be taken in the order demonstrated in the drawings. For example, the operator may choose to create new transverse fractures (FIGS. 4I through 4P) in the second zone 420 before creating the transverse fractures (FIGS. 4B through 4J) in the first 410 and third 430 zones. Alternatively, transverse fractures may be created in the first 410 and third 430 zones (FIGS. 4E through 4G) separately rather than simultaneously. In addition, once transverse fractures are created in the first 410, second 420, and third 430 zones, additional transverse fractures may be formed simultaneously in accordance with the steps shown in FIGS. 2E through 2J. Thus, regardless of the order in which transverse fractures are created, the complexity of the fracture network within the subsurface formation 450 is beneficially increased.

It is further noted that the wellbore 400 with its three zones 410, 420, 430 is merely illustrative. The steps presented incident to the wellbore 400 may be taken through just two adjoining zones without the presence of a third zone. Alternatively, there may be more than three zones. As discussed above, the use of three zones and the nomenclature used to refer to the individual zones is for explanatory purposes. The order of operations on the individual zones may be independent of the ordinal assigned to the zone. For example, while a step is illustrated and discussed as being performed on a first zone relative to a second zone, the step may be performed on the second relative to the first, the second relative to the third, the fifth relative to the sixth, or any other pair of adjacent zones.

Regardless of the number of zones, it can be seen that multiple cycles of producing and fracturing may be employed in order to create an ever-expanding network of fractures. However, in low-permeability formations the fracture networks created within the separate zones may or may not interconnect. Accordingly, an additional optional fracturing step may be employed. That step involves the placement of additional perforations and corresponding fractures intermediate to the first 410, second 420, and third 430 zones.

FIG. 4Q presents this optional additional step. In FIG. 4Q, new intermediate perforations have been formed along the casing 402. First, perforations 462 are formed between the first zone 410 and the second zone 420. Second, perforations 472 are formed between the second zone 420 and the third zone 430. Intermediate fractures 464 are created from perforations 462, while intermediate fractures 474 are created from perforations 472.

It is preferred that the perforations 462, 472 be oriented at an angle that is non-transverse to the casing 402. In this way, fractures 464, 474 are at least initially propagated at an angle, and may intersect with fractures in adjoining zones.

As can be seen, FIGS. 4A through 4Q present steps for a process of producing hydrocarbon fluids. The steps may be set out textually in a flowchart. FIGS. 5A through 5C present such a flow chart, and show steps for a method 500 of producing hydrocarbon fluids.

In the method 500, the hydrocarbon fluids are produced from a subsurface formation. The subsurface formation represents a reservoir containing hydrocarbon fluids. The fluids may be, for example, methane and other lighter hydrocarbon fluids. The reservoir may also include so-called acid gases such as carbon dioxide and hydrogen sulfide. The reservoir may also incidentally contain water or brine.

In any instance, the subsurface formation is a low-permeability formation. The formation may have a permeability less than, for example, about 10 millidarcies. In this instance, the reservoir may be a tight-gas formation, a shale gas formation, or a coal bed methane formation.

The method 500 first includes providing a wellbore in the subsurface formation. This is shown at Box 505. The wellbore has been completed as a deviated wellbore. Preferably, the deviated wellbore is a substantially horizontal wellbore within the subsurface formation. The wellbore has been perforated along at least a first zone and a second zone.

The method 500 also includes fracturing the subsurface formation along the first and second zones. This is provided at Box 510. Fracturing the formation along these zones creates one or more substantially vertical fractures extending from the wellbore.

The method 500 further includes producing hydrocarbon fluids through the vertical fractures along the first and second zones. This is seen at Box 515. In one aspect, the vertical fractures extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.

The method 500 additionally includes injecting a fluid into the subsurface formation. This is provided at Box 520. The fluid is preferably a hydraulic fluid such as brine. However, liquid CO₂, foamed nitrogen, or other non-reactive fluids may also be injected.

In the injecting step of Box 520, the fluid is injected through perforations in the second zone. This serves to raise the reservoir pressure in the subsurface formation along the first zone. This also helps to cause a change in the in situ stresses within the subsurface formation along the first zone. However, the fluid preferably is not injected at a parting pressure and does not extend existing fractures.

The method 500 may also include monitoring the wellbore. This is shown at Box 525. The wellbore is monitored to determine when a change in orientation of maximum principal stress may occur within the subsurface formation along the first zone. The change in maximum principal stress occurs as a result of producing fluids from the first zone and injecting the fluid into the second zone.

The wellbore may be monitored in a number of different ways. For example, monitoring the wellbore may comprise determining when a designated volume of hydrocarbon fluids have been produced from the first zone or from the subsurface formation in general. Alternatively, monitoring the wellbore may comprise determining when a designated reduction in reservoir pressure within the subsurface formation along the first zone has taken place. This may be done through reservoir simulation or based on experience with existing wells in the field. Alternatively, monitoring the wellbore may comprise determining when a selected volume of fluid has been injected into the subsurface formations through the perforations in the second zone.

Alternatively still, monitoring the wellbore may comprise determining when a selected period of time of production has taken place from the first zone. And still alternatively, monitoring the wellbore may comprise determining whether micro-seismic readings or tilt-meter readings indicate a change in in situ stresses. Of course, combinations of these techniques are preferably employed.

The method 500 further includes injecting a fluid into the subsurface formation through perforations in the first zone. This is seen at Box 530. The injection of fluid in the first zone is at high pressures, and causes a propagation of fractures in the subsurface formation along the first zone. The direction of maximum principal stress has been changed in the near-wellbore region along the first zone. Accordingly, the fractures tend to propagate at least partially towards the second zone.

The method 500 also includes producing hydrocarbons. This is shown at Box 535. Hydrocarbon fluids are produced through the perforations along the first zone. Preferably, hydrocarbon fluids are also produced through the perforations along the second zone as well. This is seen at Box 540.

The method 500 as described above only recites two zones. However, the method 500 may be applied to a wellbore that is perforated in more than two zones. In one aspect, the wellbore is perforated to create new perforations along a third zone. This is provided at Box 545. Perforations may be provided along the first zone, the second zone, and a third zone, with the zones preferably being separated by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters). As described above, the methods 500 may be performed on wellbores having multiple zones and may be performed simultaneously on more than two zones and may be performed sequentially on more than two zones. The specific manner of implementation may depend on the size of the field, the age of the field, or other factors that may become apparent to an operator. For example, the methods may be applied to more than two zones simultaneously and then later applied to still further zones.

The method 500 would then include fracturing the subsurface formation along the third zone to form additional vertical fractures extending from the wellbore. This is seen at Box 550. The perforating 545 and fracturing 550 steps may be conducted in stages with the first, second, and third zones using multi-interval procedures known in the art of well completions.

Where a third zone is perforated, the method 500 also includes producing hydrocarbon fluids through the vertical fractures in the third zone. This is shown at Box 555. The producing step of Box 555 may take place with the producing step of Box 515.

The method 500 still includes injecting a fluid into the subsurface formation through perforations in the second zone. This was provided at Box 520. The injection step of Box 520 will further raise reservoir pressure in the subsurface formation along the third zone, and will further cause a change in the in situ stresses within the subsurface formation along the third zone. This is indicated at Box 560. During this time, hydrocarbon fluids continue to be produced from the third zone in accordance with the producing step of Box 555.

Where a third zone is perforated, the method 500 also includes injecting a fluid into the subsurface formation through perforations in the third zone. This is provided at Box 565. The injection step of Box 565 creates a first set of new fractures in the subsurface formation along the third zone. These new fractures propagate at least partially towards the second zone.

The method 500 next includes again producing hydrocarbon fluids from the third zone. This is provided at Box 570. Preferably, hydrocarbon fluids are also simultaneously produced from the first and second zones. Thus, the step of producing in Box 570 may take place simultaneously with the producing step of Box 535.

It is noted here that the process of injecting fluid in one zone to increase reservoir pressure and to change in situ stresses in an adjoining zone may be applied in any order. Further, the process may be alternated such that after one zone has been re-fractured and produced, an adjoining zone may be re-fractured and produced. Thus, in the method 500, after producing fluids from the first, second and third zones in Boxes 535 and 570, production is temporarily suspended from the first zone. This is seen at Box 575.

After discontinuing the production of fluids from the first zone, fluid is then injected into the subsurface formation through perforations in the first zone. This is shown at Box 580. This injection is not for the purpose of creating new fractures in the first zone, but to raise reservoir pressure in the subsurface formation along the second zone. This causes a change in the in situ stresses within the subsurface formation along the second zone.

The method 500 then includes injecting a fluid into the subsurface formation through perforations in the second zone. This is provided at Box 585. The injection of fluids into the second zone is at high pressures, thereby causing a propagation of fractures in the subsurface formation along the second zone at least partially towards the first zone.

The method 500 then includes producing hydrocarbons through the perforations along the second zone. This is seen at Box 590.

The steps of Boxes 580 through 590 may be applied again with respect to the third zone. The result is that additional fractures are created in the second zone that extends at least partially towards the third zone. Thus, a more complex network of fractures is created in the subsurface formation, increasing the exposure of the formation to production channels and the wellbore.

It can be seen that the method 500 involves the selective injection of fluids at different pressures and in different stages. Further, the method 500 involves the production of fluids from selected zones at different stages. The steps of the method 500 may be aided through the use of packers, fracturing ports, mechanical plugs, sand plugs, sliding sleeves, and other devices known in the art.

The methods 300 and 500 of FIGS. 3A-3B and FIGS. 5A-5C, respectively, relate to the creation of a fracture network from a single wellbore. However, the concept of manipulating in situ stresses to increase the complexity of a fracture network may be approached on a multi-well basis.

In order to optimize the production of hydrocarbons from a formation, the reservoir engineer or other field developer designs a desired fracture network. FIG. 6A presents such an illustrative fracture network 600A. The fracture network 600A comprises a series of interconnecting fractures 610, 620. Each of the fractures 610, 620 is oriented in a substantially vertical plane.

In the illustrative fracture network 600A, the fractures 610, 620 are arranged in pairs 650A. Each of the fractures 610 is oriented along an x-y plane. At the same time, each of the fractures 620 is oriented along a z-y plane. In this way, each of the x-y fractures 610 is intersected at substantially a right angle by a single corresponding z-y fracture 620. A plurality of pairs 650A is provided for the fracture network 600A.

The concept of intersecting fractures shown in the fracture network 600A is but one of many possible arrangements. FIG. 6B presents an alternate but related arrangement for a fracture network 600B. Here, instead of providing a single z-y fracture 620 with each of the x-y fractures 610, two z-y fractures 620 are provided with each of the x-y fractures 610. Such groupings are shown at 650B.

Other related variations may readily be employed. For example, instead of providing a single z-y fracture 620 with each of the x-y fractures 610, three z-y fractures 620 may be provided with each of the x-y fractures 610. Inversely, instead of providing a single x-y fracture 610 with each of the z-y fractures 620, two, three, or more x-y fractures 610 may be provided with each of the z-y fractures 610.

In order to create such an arrangement of fractures 610, 620, the reservoir engineer (or other field developer) may complete a plurality of horizontal wells in a subsurface formation. In one aspect, some wells are completed along an x-axis within the formation, while other wells are completed along a z-axis in the formation. The purpose is to provide substantial coverage of a field with a fracture network.

A fracturing fluid is injected into a first set of wells, such as the horizontal wells completed along the x-axis, in order to create fractures in the formation in a first vertical orientation. This may be done in accordance with the steps shown, for example, in FIGS. 2A through 2C. Subsequently, steps are taken to change the orientation of the minimum principal stress in the formation. This may be done in accordance with the step shown, for example, in FIG. 2E. Thereafter, a fracturing fluid is injected into a second set of wells, such as the horizontal wells completed along the z-axis, in order to create fractures in the formation in a second vertical orientation along the x-y plane. In the arrangements of FIGS. 6A and 6B, the second vertical orientation is at substantially a 90-degree angle to the first vertical orientation.

FIG. 7 provides a plan view of a hydrocarbon development area 700, in one embodiment. The hydrocarbon development area 700 has a surface 710. The hydrocarbon development area 700 also has a subsurface 720. The subsurface 720 includes a formation 725 containing hydrocarbon fluids. The formation 725 comprises a rock matrix having low permeability. The formation 725 may have, for example, a permeability less than about 10 millidarcies.

It is desirable to optimize the production of hydrocarbon fluids from the formation 725. Because the formation 725 has limited permeability, one way of optimizing production is by creating a network of interconnecting fractures. In order to create the fracture network, a first set of wells is completed horizontally. The wellbores for the first set of wells are shown at 732. These wellbores 732 extend along an x-axis. Thereafter, the subsurface formation 725 is fractured from perforations in the wellbores 732 for the first set of wells. Fractures are seen at 740. Hydrocarbon fluids are then produced from through the fractures 740 and the corresponding wellbores 732.

After a period of production, the in situ stress field within the subsurface formation 725 is changed. This may be as a natural result of the fluid production process. Alternatively, this may be as a result of selective injection of water or other fluids into the subsurface formation 725 in order to increase in situ pressure. In any instance, a second set of wells having wellbores 734 is also formed. These wellbores are also completed horizontally, and are oriented along a z-axis.

After the in situ stress field within the subsurface formation 725 is changed, the subsurface formation 725 is fractured from perforations in the wellbores 734 for the second set of wells. Illustrative fractures from the wellbores 734 are seen at 750. Hydrocarbon fluids are then produced from through the fractures 750 and the corresponding wellbores 734.

It is noted that the wellbores 732 along the x-axis and the wellbores 734 along the z-axis cross. They do not intersect, but they do cross. This allows the respective fractures 740, 750 to intersect. The intersecting fractures 740, 750 create a fracture network analogous to the fracture networks 650A, 650B shown in FIGS. 6A and 6B.

FIG. 8 is a flow chart showing steps for performing a method 700 for creating a network of fractures in a reservoir, in one embodiment. The reservoir preferably represents a rock matrix having a low permeability. For example, the permeability may be less than 10 millidarcies.

The reservoir may be a hydrocarbon-producing reservoir. For example, the reservoir may contain methane and other hydrocarbon gases. In this instance, the reservoir may be a tight-gas formation, a shale gas formation, or a coal bed methane formation. The reservoir may also include so-called acid gases, such as carbon dioxide and hydrogen sulfide. The reservoir may also incidentally contain water or brine.

Alternatively, the reservoir may be a geothermal zone containing water and, possibly, minerals. In this instance, the reservoir will produce steam.

The method 800 generally includes designing a desired fracture network. This is shown at Box 810. The fracture network may be, for example, in accordance with the illustrative fracture networks 650A, 650B shown and discussed in FIGS. 6A and 6B. The step of designing a desired fracture network of Box 810 is done using geomechanical simulation, which involves use of a software program and a processor.

The method 800 also includes determining required in situ stresses to create the fracture network within the reservoir. This is provided at Box 820. Determining required in situ stresses may be done in several ways. For example, downhole pressure measurements may be taken from existing wells. Such measurements are indicative of pore pressure acting within a rock matrix. Alternatively or in addition, micro-seismic testing may be conducted. Alternatively or in addition, tiltmeter readings may be monitored.

In a preferred aspect, downhole stress modeling may be conducted. For example, ABAQUS™ software may be used to develop in situ stresses and resulting fractures. To run a model, the rock matrix making up the reservoir is initialized with certain mechanical properties. Such properties may be, for example, elastic moduli and Poisson ratios. Elastic moduli and Poisson ratios may be estimated based on interpreted lithologies for the rocks included in the model.

A stress field may be demonstrated by x, y, and z coordinates. In the Piceance Basin, for instance, the in situ stress field will be affected in one of the horizontal directions due to tectonic forces acting from the Rocky Mountain range to the east. From the stress field modeling, the direction of least principal stress is determined. For formations deeper than about 1,000 feet, the direction of least principal stress will likely be in the “x” or “z” directions, where the x and z directions are horizontal and “y” is the vertical direction, such that hydraulically-induced fractures will be oriented in plane perpendicular to the “x” or “z” direction.

The method 800 further includes designing a layout of wells to alter the in situ stresses. This is provided at Box 830. Designing such a layout of wells means that wells are completed in the subsurface for the production and/or injection of fluids for the purpose of altering the in situ stress field. The layout of wells may be, for example, in accordance with the layout of wellbores 732 and 734 of FIG. 7.

The method 800 also includes injecting a fracturing fluid under pressure into the reservoir. The purpose is to create an initial set of fractures. This is shown at Box 840. The fractures will likely extend in a vertical plane through the formation, as shown in FIG. 2C. The result is that the fractures do not interconnect and provide limited exposure of the wellbores to the formation.

Historically, an operator might choose to extend the length of the fractures in order to increase exposure of the wellbores to the formation. Fractures have been reported in some field developments that extend many thousands of feet. However, this is undesirable where the fractures are anticipated to form in a vertical plane. In this respect, the fractures may propagate beyond the targeted production intervals and, potentially, into aquifers or unconsolidated formations.

In the method 800, a next step is taken to monitor the in situ stresses in the reservoir. This is seen at Box 850. Monitoring the in situ stresses in the reservoir may be done in several ways. These are generally shown in the flow chart of FIG. 9.

FIG. 9 is a flow chart showing illustrative steps that may be taken for monitoring in situ stress fields. First, monitoring may include conducting downhole pressure measurements. This is seen at Box 910. Alternatively or in addition, monitoring may include micro-seismic and/or tiltmeter monitoring. This is provided at Box 920. Alternatively or in addition, monitoring may include taking readings from tiltmeters on a surface above the reservoir. This is shown at Box 930. Alternatively or in addition, monitoring may include performing downhole stress modeling. This is seen at Box 940. Of course, combinations of any of these techniques may be employed.

The method 800 additionally includes updating the geomechanical simulation based on the monitored in situ stresses. This is indicated at Box 855. Further, the method 800 includes designing a program of modifying the in situ stress within the stress field. This is seen at Box 860. The step of designing a program of Box 860 is also done using geomechanical simulation. The geomechanical simulations may be performed using commercially available software capable of capturing the complex interplay between the in situ stress state and the engineering practices. Examples of such software include finite element software (e.g. Abaqus or ELFEN); and discrete element software (e.g. PFC3D or ELFEN).

The geomechanical simulations incorporate fully-coupled constitutive relations that enable mathematical representations of in situ stress state and pore pressure, rock mechanical properties, engineering stimulation practices at the wellbores, and field production. Newly acquired data is input into the geomechanical simulations to foster iteration between history matching and predictive modes.

The method 800 also includes modifying the in situ stresses in the reservoir. This is seen at Box 865. Modifying the in situ stresses permits the operator to determine when the direction of least principal stress within the in situ stress field has changed.

The in situ stresses may be modified through reservoir depletion over time. In this instance, the step 860 will comprise producing hydrocarbon fluids from the reservoir. Alternatively or in addition, the step 865 may comprise injecting a fluid into the reservoir. The fluid is injected at a pressure lower than the parting pressure of the rock matrix. The fluid may be injected into each of a plurality of wells either (i) simultaneously, or (ii) in stages such that fluid is injected into one or more wells or one or more zones sequentially.

In a related embodiment, modifying the in situ stresses further comprises (i) specifying a length of time for injecting for selected wells, (ii) specifying a viscosity of fluid for injection into selected wells, (iii) modifying a temperature of the reservoir, or (iv) combinations thereof. Modifying a temperature of the reservoir may comprise (i) injecting a heated gas into the reservoir, (ii) applying resistive heat to a rock matrix comprising the reservoir, (iii) actuating one or more downhole combustion burners, (iii) injecting a cooler fluid into the reservoir or (v) combinations thereof.

Modifying the in situ stresses may also comprise establishing assistive fracture paths. The assistive fracture paths are in addition to the initial fractures created in step 840. Establishing the assistive fracture paths may be done by creating a plurality of radially offset perforations into the reservoir through a plurality of wells. The orientation of the perforations may also be adjusted so that the perforations do not extend transverse to the wellbores. Alternatively or in addition, establishing the assistive fracture paths may be done by injecting an acidic fluid through a plurality of wells to create worm holes in the reservoir.

Once the in situ stresses have been modified, the reservoir may be further fractured. This enables a true network of fractures to be created, as opposed to simply re-opening or, perhaps, extending the same fractures in the same direction. Thus, the method 800 further includes injecting a fluid under pressure into the reservoir in order to expand upon the initial set of fractures and to create the network of fractures. This is shown at Box 870. Injecting a fluid into the reservoir to create the network of fractures may be done by determining pump rates and associated shear rates for selected wells.

In one aspect of the method 800, at least two of the wells in the layout of wells are completed for the production of hydrocarbon fluids. In this instance, the network of fractures is designed to optimize production of the hydrocarbon fluids. Injecting a fluid into the reservoir under pressure in accordance with the steps of Boxes 840 and 870 may comprise injecting the fluid through wells that have been completed principally for the production of hydrocarbon fluids.

In another aspect, at least two of the wells in the layout of wells are being completed for the injection of fluids as part of enhanced oil recovery. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 may further comprise injecting the fluid through selected wells that are completed for the injection of fluids. The fluids being injected may represent an aqueous fluid such as brine.

In yet another aspect, at least two of the wells in the layout of wells are completed for the production of geothermally-produced steam. The network of fractures is designed to optimize heat transfer for geothermal applications. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 may comprise injecting the fluid through selected wells completed for the production of the geothermally-produced steam.

In still another aspect, at least two of the wells in the layout of wells are completed for the injection of acid gases. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 comprises injecting the fluid through selected wells completed for the injection of acid gases. The acid gases may primarily comprise carbon dioxide. The carbon dioxide may be injected as part of an enhanced oil recovery project. Alternatively, the carbon dioxide may be injected as part of a sequestration operation. In this instance, the network of fractures is designed to optimize CO₂ storage capacity.

In yet another aspect, at least two of the wells in the layout of wells are completed for the injection of drill cuttings. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 comprises injecting the drill cutting through selected wells for injection into the reservoir.

In one embodiment of the methods herein, the reservoir comprises two or more zones. In this instance, the network of fractures is created within at least two different zones. Designing a desired fracture network system then involves designing a fracture network system in each of the at least two zones. In addition, injecting a fluid under pressure into the reservoir involves injecting a fluid into each of the at least two zones so as to create the network of fractures within the at least two zones. For example, the network of fractures may be created in the manner described above in connection with FIGS. 3A-3B and/or FIGS. 5A-5C.

In another embodiment, a plurality of wells within the layout of wells has already been perforated into the reservoir. Further, the reservoir has undergone hydrocarbon production for a period of time. In this instance, injecting a fluid under pressure into the reservoir in order to create the network of fractures involves re-fracturing each of the plurality of wells.

As can be seen, methods are offered herein to enhance hydrocarbon production from subterranean formations by manipulating the downhole in situ stresses. Manipulating in situ stresses allows the operator to create fractures in different directions and to enhance reservoir connectivity. In accordance with the methods, a desired fracture network system is first designed for draining the reservoir. The in situ stresses needed to create the fracture network system are then determined. A comprehensive system consisting of well/pad layout and well architecture is designed to alter the stress field around the individual wells. A customized network of fractures is then created.

As a result of fracturing, there is increased fracture complexity and increased reservoir access. The change in downhole in situ stresses and accompanying fracture orientation are preferably monitored or modeled to provide continuous feedback. This is indicated at Box 880 of FIG. 8. The step of Box 880 may, for example, be in accordance with any of the steps shown in FIG. 9. The reservoir may again be fractured as the stress field changes.

The methods disclosed herein are particularly beneficial for the development of unconventional reservoirs such as tight gas, shale gas, and coal bed methane, and the recovery of gas. The methods are also beneficial for the sequestration of CO₂. In geothermal applications, the present methods will help to increase contact area from the wellbore to the reservoir. For water/cuttings injection wells, the methods can be used to control fracture geometry and orientation.

While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof. 

What is claimed is:
 1. A method of creating a network of fractures in a reservoir, the reservoir having an in situ stress field, and the method comprising: designing a desired fracture network system using geomechanical simulation; determining required in situ stresses to create the desired fracture network within a reservoir having an in situ stress field; designing a layout of wells to alter the in situ stresses within the stress field; injecting a fracturing fluid under pressure into the reservoir in order to create an initial set of fractures; monitoring the in situ stresses within the stress field; updating the geomechanical simulation based on the monitored in situ stresses; designing a program of modifying the in situ stress within the stress field using geomechanical simulation; modifying the in situ stresses within the stress field by implementing at least one aspect of the program; and injecting a fracturing fluid under pressure into the reservoir in order to expand upon the initial set of fractures and to create the desired fracture network.
 2. The method of claim 1, wherein the reservoir has a permeability less than 10 millidarcies.
 3. The method of claim 2, wherein: at least two wells in the layout of wells are completed for the production of hydrocarbon fluids; and the network of fractures is designed to optimize production of the hydrocarbon fluids.
 4. The method of claim 3, wherein injecting a fracturing fluid under pressure into the reservoir comprises injecting the fluid through the at least two wells completed for the production of hydrocarbon fluids.
 5. The method of claim 3, wherein at least two wells in the layout of wells are completed for the injection of fluids as part of enhanced oil recovery.
 6. The method of claim 5, wherein injecting a fluid under pressure into the reservoir comprises injecting the fluid through the wells completed for the injection of fluids.
 7. The method of claim 6, wherein the fluids represent an aqueous fluid.
 8. The method of claim 4, further comprising: producing hydrocarbon fluids from the wells completed for the production of hydrocarbon fluids after the initial set of fractures is created.
 9. The method of claim 8, wherein modifying the in situ stresses comprises the producing of hydrocarbon fluids.
 10. The method of claim 8, wherein modifying the in situ stresses comprises injecting a fluid into at least a portion of the reservoir in order to increase pore pressure within the in situ stress field.
 11. The method of claim 2, further comprising: after monitoring the in situ stresses within the stress field, again injecting a fracturing fluid under pressure into the reservoir.
 12. The method of claim 1, wherein: at least two wells in the layout of wells are completed for the production of geothermally-produced steam; injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the production of the geothermally-produced steam; and the network of fractures is designed to optimize heat transfer for geothermal applications.
 13. The method of claim 2, wherein at least two wells in the layout of wells are completed for the injection of acid gases; and injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of acid gases.
 14. The method of claim 13, wherein: the acid gases primarily comprise carbon dioxide; and the carbon dioxide is injected as part of an enhanced oil recovery project.
 15. The method of claim 13, wherein: the acid gases primarily comprise carbon dioxide; the carbon dioxide is injected as part of a sequestration operation; and the network of fractures is designed to optimize CO₂ storage capacity.
 16. The method of claim 2, wherein: at least two wells in the layout of wells are completed for the injection of drill cuttings; and injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of drill cuttings.
 17. The method of claim 2, wherein determining required in situ stresses to create the desired fracture network comprises (i) reviewing downhole pressure measurements from existing wells, (ii) reviewing micro-seismic monitoring conducted in existing wells, (iii) conducting downhole stress modeling, (iv) reviewing tiltmeter readings, or (v) combinations thereof.
 18. The method of claim 2, wherein: injecting a fluid under pressure into the reservoir comprises injecting a fluid through a plurality of wells that are part of the layout of wells; and modifying the in situ stresses comprises injecting a fluid under pressure into each of the plurality of wells either (i) simultaneously, or (ii) in stages such that fluid is injected into one or more wells sequentially.
 19. The method of claim 18, wherein modifying the in situ stresses further comprises (i) specifying a length of time for injecting for selected wells, (ii) specifying a viscosity of fluid for injection into selected wells, (iii) modifying a temperature of the reservoir, or (iv) combinations thereof.
 20. The method of claim 19, wherein modifying a temperature of the reservoir comprises (i) injecting a heated gas into the reservoir, (ii) applying resistive heat to a rock matrix comprising the reservoir, (iii) actuating one or more downhole combustion burners, (iv) injecting a cooler fluid into the reservoir, or (v) combinations thereof.
 21. The method of claim 2, wherein modifying the in situ stresses comprises providing new perforations into the reservoir from selected wellbores, with the perforations being shot at a non-transverse angle relative to the wellbores.
 22. The method of claim 2, wherein modifying the in situ stresses comprises producing hydrocarbon fluids from the reservoir.
 23. The method of claim 2, wherein modifying the in situ stresses comprises injecting a fluid into the reservoir to increase pore pressure.
 24. The method of claim 2, wherein modifying the in situ stresses comprises establishing an assistive fracture path (i) by creating a plurality of radially offset perforations into the reservoir through a plurality of wells, (ii) by injecting an acidic fluid through a plurality of wells to create worm holes in the reservoir, or (iii) combinations thereof.
 25. The method of claim 2, wherein injecting a fluid into the reservoir to create the network of fractures comprises determining pump rates and associated shear rates for selected wells.
 26. The method of claim 2, wherein: the reservoir comprises two or more zones; and the network of fractures is created within at least two different zones, such that: designing a desired fracture network system comprises designing a fracture network system in each of the at least two zones, and injecting a fluid under pressure into the reservoir comprises injecting a fluid into each of the at least two zones so as to create the network of fractures within the at least two zones.
 27. A method of producing hydrocarbons from a subsurface formation, the formation having a permeability less than about 10 millidarcies, and the method comprising: providing a wellbore in the subsurface formation, the wellbore having been completed as a deviated wellbore, and the wellbore having been perforated within the subsurface formation along at least a first zone and a second zone; fracturing the subsurface formation along the first and second zones to form substantially vertical fractures extending from the wellbore; producing hydrocarbon fluids through the vertical fractures along the first and second zones; monitoring the wellbore to determine when a change in orientation of the maximum principal stress occurs within the subsurface formation along the first and second zones; injecting a fracturing fluid into the subsurface formation through perforations in the first and second zones, thereby creating a first new fractures within the subsurface formation that at least partially extends from the vertical fractures along a plane that is substantially transverse to the vertical fractures; and producing hydrocarbons through the first new fractures and through the vertical fractures along the first and second zones.
 28. The method of claim 27, wherein: the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation; and the vertical fractures extend substantially transverse to the wellbore.
 29. The method of claim 28, wherein: monitoring the wellbore comprises (i) determining when a designated volume of hydrocarbon fluids have been produced from the wellbore; (ii) determining when a designated reduction in reservoir pressure within the subsurface formation has taken place; (iii) determining when a selected period of time of production has taken place; (iv) determining whether micro-seismic readings indicate a change in in situ stresses; (v) or combinations thereof.
 30. The method of claim 28, wherein: the wellbore has further been perforated within the subsurface formation along a third zone; fracturing the subsurface formation further comprises fracturing the subsurface formation along the third zone to form additional vertical fractures extending from the wellbore; producing hydrocarbon fluids through the vertical fractures further comprises producing hydrocarbon fluids along the third zone; monitoring the wellbore further comprises monitoring the wellbore to determine when a change in maximum principal stress may occur within the subsurface formation along the third zone; injecting a fracturing fluid into the subsurface formation to create the first new fractures further comprises injecting a fracturing fluid through perforations in the third zone; and producing hydrocarbons through the first new fractures further comprises producing hydrocarbons through the vertical fractures along the third zone.
 31. The method of claim 30, further comprising: injecting a fracturing fluid into the subsurface formation through perforations in the first, second, and third zones, thereby creating second new fractures within the subsurface formation that at least partially extend from the (i) vertical fractures, (ii) the first new fractures, or (iii) both, along a plane that is substantially transverse to the vertical fractures; and producing hydrocarbons through (i) the second new fractures, (ii) the first new fractures, and (iii) the vertical fractures along the first, second, and third zones.
 32. The method of claim 31, wherein the perforations along the first zone, the second zone, and the third zone are separated by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters).
 33. The method of claim 31, wherein the vertical fractures extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.
 34. The method of claim 31, further comprising: perforating the wellbore to create new perforations along a selected zone, wherein the new perforations are shot at a non-transverse angle relative to the wellbore; injecting a fracturing fluid into the subsurface formation through the new perforations in the selected zone in order to fracture the subsurface formation along the selected zone; and producing hydrocarbon fluids through perforations along the selected zone.
 35. A method of producing hydrocarbons from a subsurface formation, the formation having a permeability less than about 10 millidarcies, and the method comprising: providing a wellbore in the subsurface formation, the wellbore having been completed as a deviated wellbore, and the wellbore having been perforated along at least a first zone and a second zone; fracturing the subsurface formation along the first and second zones to form substantially vertical fractures extending from the wellbore; producing hydrocarbon fluids through the vertical fractures along the first and second zones; injecting a fluid into the subsurface formation through perforations in the second zone, thereby raising reservoir pressure in the subsurface formation along the first zone and causing a change in the in situ stresses within the subsurface formation along the first zone; injecting a fluid into the subsurface formation through perforations in the first zone, thereby causing a propagation of fractures in the subsurface formation along the first zone at least partially towards the second zone; and producing hydrocarbons through the perforations along the first zone.
 36. The method of claim 35, wherein: the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation; and the vertical fractures extend substantially transverse to the wellbore.
 37. The method of claim 36, further comprising: producing hydrocarbons through the perforations along the second zone along with the production of hydrocarbons from the first zone.
 38. The method of claim 36, further comprising: monitoring the wellbore to determine when a change in maximum principal stress may occur within the subsurface formation along the first zone as a result of injecting the fluid into the second zone.
 39. The method of claim 36, wherein: monitoring the wellbore comprises (i) determining when a designated volume of hydrocarbon fluids have been produced from the first zone; (ii) determining when a designated reduction in reservoir pressure within the subsurface formation along the first zone has taken place; (iii) determining when a selected period of time of production has taken place; (iv) determining whether micro-seismic readings indicate a change in in situ stresses; (v) determining any changes in in situ stresses; (vi) determining when a selected volume of fluid has been injected into the subsurface formations through the perforations in the second zone; or (vii) combinations thereof.
 40. The method of claim 36, wherein: the wellbore has further been perforated within the subsurface formation along a third zone; fracturing the subsurface formation further comprises fracturing the subsurface formation along the third zone to form additional vertical fractures extending from the wellbore; producing hydrocarbon fluids through the vertical fractures further comprises producing hydrocarbon fluids along the third zone; injecting a fluid into the subsurface formation through perforations in the second zone further raises reservoir pressure in the subsurface formation along the third zone, and further causes a change in the in situ stresses within the subsurface formation along the third zone; and the method further comprises: injecting a fluid into the subsurface formation through perforations in the third zone, thereby causing a propagation of fractures in the subsurface formation along the third zone at least partially towards the second zone; and producing hydrocarbons through the perforations along the third zone.
 41. The method of claim 40, further comprising: producing hydrocarbons through the perforations along the first and second zones along with the production of hydrocarbons from the third zone.
 42. The method of claim 36, wherein the perforations along the first zone and the second zone are separated by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters).
 43. The method of claim 36, wherein the fractures extending substantially transverse to the wellbore extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.
 44. The method of claim 36, further comprising: discontinuing production of hydrocarbons from the first zone; injecting a fluid into the subsurface formation through perforations in the first zone, thereby raising reservoir pressure in the subsurface formation along the second zone and causing a change in the in situ stresses within the subsurface formation along the second zone; injecting a fluid into the subsurface formation through perforations in the second zone, thereby causing a propagation of fractures in the subsurface formation along the second zone at least partially towards the first zone; and producing hydrocarbons through the perforations along the second zone.
 45. The method of claim 40, further comprising: discontinuing production of hydrocarbons from the third zone; injecting a fluid into the subsurface formation through perforations in the third zone, thereby raising reservoir pressure in the subsurface formation along the first zone and causing a change in the in situ stresses within the subsurface formation along the first zone; injecting a fluid into the subsurface formation through perforations in the second zone, thereby causing a propagation of fractures in the subsurface formation along the second zone at least partially towards the third zone; and producing hydrocarbons through the perforations along the second zone.
 46. The method of claim 36, further comprising: perforating the wellbore to create new perforations along a selected zone, wherein the new perforations are shot at a non-transverse angle relative to the wellbore; injecting a fracturing fluid into the subsurface formation through the new perforations in the selected zone in order to fracture the subsurface formation along the selected zone; and producing hydrocarbon fluids through perforations along the selected zone.
 47. A method of creating a network of fractures in a reservoir, the reservoir having an in situ stress field, and the method comprising: monitoring the in situ stresses within the stress field; injecting a fracturing fluid under pressure through a first set of perforations into the reservoir in order to create an initial set of fractures; producing native fluids from the reservoir to change in situ stresses within the stress field; and injecting a fracturing fluid under pressure through a second set of perforations into the reservoir in order to expand upon the initial set of fractures and to create the network of fractures.
 48. The method of claim 47, further comprising: designing a desired fracture network system; determining required in situ stresses to create the desired fracture network within the reservoir; and designing a layout of wells to alter the in situ stresses within the stress field. 